Vibration wave characteristics in Conventional and Periodic Drill string models

Many problems in a drilling operation can be caused by excessive contact forces between the drill pipe and the casing or hole wall. The contact force pipe and the casing or hole wall. The contact force is mainly controlled by the hole curvature, drill pipe stiffness, and the axial load on the drill pipe. pipe stiffness, and the axial load on the drill pipe. This paper discusses the relationship between the magnitude of the contact forces and the above three variables, as well as several other less significant variables. Introduction The lateral force with which the drill string interacts with the casing or open hole wall should be of vital concern in a drilling operation. Large lateral forces can result in excessive casing wear, excessive drill pipe and tool joint wear, and key seats in the hole wall. An understanding of the factors that control the lateral contact forces may allow preventative action to be taken before a problem develops. The problem of excessive contact force between the drill pipe and the hole wall has been recognized for many years. It was addressed in 1960 by Lubinski, but it has only been during the last few years that detailed computer modeling of the problem has been feasible. This paper presents the results of a finite element computer study of the variables that affect the magnitude of the contact forces under a variety of conditions. The parameters were chosen to represent conditions that may occur in realistic drilling operations. Finite Element Model During 1975 a consulting firm was contracted and directed by Amoco to write a dynamic triaxial finite element computer program for the analysis of bottom hole assemblies. This program can be used to analyze any multi-component drill string in a wellbore. The drill string can be divided into a maximum of 51 elements of uniform cross sectional geometry and uniform material. An iterative process of solving for deflections and forces is then performed until the drill string deflections converge within the boundary conditions of the borehole. The required input data is a description of the drill string, wellbore diameter, wellbore survey, drilling fluid density, and axial load (weight on bit). The computed data includes the forces and deflections for each node point. Further discussion of the program is included in the appendix. Two drill pipe models were investigated before one was chosen for the study. The first model represented a joint of drill pipe with five equal length finite elements and the tool joint as a single element with its length equal to the tool joint length. This model was unstable under certain combinations of axial load and hole curvatures. The second model represented a joint of drill pipe with two finite elements and the tool joint as a zero length element. The zero length element resulted in a single point of contact with the hole wall rather than a point of contact on each end of a short element. Both models gave the same results for the cases in which the first model would converge, thus the second model was used for the study. Figure 1 shows a diagram of the drill pipe configuration that was used for decreasing curvature and Figure 2 shows the increasing curvature configuration. Table 1 gives the drill pipe and tool joint dimensions that were used in the study. Cases were run for 3-1/2", 4-1/2", 5", 5-1/2", and 6-5/8" drill pipe, with 20", 13-3/8", 9-5/8", and 7" casing sizes. pipe, with 20", 13-3/8", 9-5/8", and 7" casing sizes. The 13-3/8", 9-5/8", and 7" casing sizes will give approximately the same results as 12-1/4", 8-3/4", and 6-1/4" open hole sizes. The effects of hole size, drill pipe size, axial load, hole curvature, length and orientation of the curve, and hole inclination were investigated. Unless otherwise noted, the drill pipe was positioned in the hole so that a tool joint would be at the center of the hole curvature. All the results presented in this paper were generated from a static (non-rotating) model. The results accurately represent the forces which develop while going in or out of the hole with the drill pipe. pipe.

Both Saudi Aramco and Total Indonesia found benefits in selecting 4 in. drill pipe with streamlined double shoulder connections for the drilling of wells, for which the 3 1/2 in. drill pipe was unsuitable. Although dealing with different environments and applications, these benefits can be summarized in "successfully drilling longer slim holes with a drill string having enhanced torsional, tensile and hydraulic characteristics at a lower overall cost". For the Saudi Aramco QTF field, Extended Reach Drilling (ERD) was required with the objective to deliver pay zones located at measured depths of 18,000 ft (for the 1,500 HP rigs) and 25,000 ft (for the 2,000 HP rigs). These depths correspond to step outs ranging from 13,000 ft to 20,000 ft respectively from the drill site. For its Kalimantan field, Total was in a need of higher torsional capacity and also an improvement of the hydraulic characteristics of the drill string. Selecting a larger size of pipe was the retained option against an upgrade of the rig pump installation. The casing and drilling program remained unchanged with the drilling of a 6 in. hole after setting the 7 in. casing, adding a constraint for fishability of the string. In both cases, fishability and torque objectives made the selection of the appropriate connection essential. The selected double shouldered connection maintained a tool joint outside diameter similar to standard 3 1/2 in. drill pipe tool joints, that maintains fishing ability of the 4 in. pipe, in casing and open hole, despite the pipe size increase. The streamline connection design provides 22,000 ft-lb working torque, an outside diameter of 4–7/8 in. and an oversized internal bore that promotes hydraulic efficiency. Other important improvements include considerable gain in pipe resistance under buckling loads, increased available pressure at the bit, better telemetry for the MWD and LWD tools and improved hole cleaning and rate of penetration. Introduction Drilling deeper, slim hole wells has revealed limitations of 3 1/2 in. drill pipe traditionally used to drill the 6 to 6–1/4 in. hole sections. The level of torque that API rotary shoulder, as well as first generation double shoulder connections, can deliver does not match the new requirements for these deeper drilling programs. This increase in drill string length also puts an additional constraint on hydraulic performance. This encouraged drilling engineers to re-evaluate the drill string design requirements and select a new configuration of pipe that would respond to these new requirements. This paper addresses these pipe and connection design considerations and provides two case histories showing the benefits that were realized from using this new drill pipe design configuration. Over 1,400,000 ft of this pipe has been built to date and is in service all over the world. It is also important to mention that this new drill pipe arrangement can also be used for drilling upper hole sections eliminating the need for a string 5 in. drill pipe in many applications. Streamlined Double Shoulder Connections for 4 in. Drill Pipe There has been increasing requirements for drill pipe with improved hydraulic performance and mechanical properties to replace 3–1/2 in. drill pipe traditionally used in slim-hole drilling.

Heave compensated response of long multi-segment drill strings

Mankind’s increased requirement for and dependence on energy resources, including the resources resulting from discovery and development of new hydrocarbon commercial reservoirs involves the use of new technologies such as optimization of the drilling process by reducing the non-productive time, the costs and the risks. Casing while drilling involves elimination of classical drilling string by using the casing string both for transmission to the bit of the mechanical energy and for circulation of drilling fluid into the well. Casing while drilling, constantly improving over time, has proven an efficient method to reduce risks, especially those related to the presence of a conventional drill string in the borehole, maintenance of borehole stability or loss of circulation. Although there is a number of technical or perception barriers related to the use of casing drilling, the important benefits of this technology related to reduced drilling time and problems associated to the drilling string make it an increasingly viable alternative to conventional drilling. The experience in applying this technology has proven that it can reduce the time of well execution and sometimes it lowers the costs in relation to drilling depth.

Parameter optimization based on deepwater drilling system simulation: A pre-salt exploration well in Brazil

A need exists for drill pipe that offers improved reliability and extended life in re-entry drilling programs where the radius of curvature is less than 60ft (i.e., >95-deg/100 ft). Steel, aluminum, and composite drill pipetraditionally utilized in these short radius drilling operations often exhibit abbreviated lives stemming from fatigue, wear, and/or physical damage. With an elastic modulus of approximately 17 msi, titanium pipe offers enhanced flexibility and reduced fiber stresses compared to steel pipe when rotated in holes of high curvature. Utilization of the most widely used titanium alloy, Ti-6Al-4V, offers a high nominal yield strength of 120 ksi with a density 56% that of steel. Combined with good corrosion and fatigue resistance in drilling and down hole fluid environments, this titanium alloy isa lightweight, highly flexible, robust, and fatigue-resistant drill pipe material. A practical and cost-optimized Ti drill pipe joint design consists of a seamless Ti-6Al-4V alloy pipe body, which is produced in standard API sizes and Range 2 and 3 lengths, to which steel tool joints are mechanically attached to the upset ends. The steel tool joints offer the advantages of lower tool joint costs, standard drill pipe make/break connection behaviour, the option for tooljoint hard banding, and elimination of welded joints. Successful development of titanium drill pipe assemblies for short-radius drilling included appropriate conditioning of the OD and ID pipe body surfaces to maximize fatigue life, optimizing the pipe end upsetting procedure, establishing the tool joint-to-pipe attachment methodology, and design and testing of a high-integrity tool joint-to-pipe connection and tool joint for optimum fatigue performance. This paper overviews these developments and the laboratory test results used to establish critical performance behaviour and requirements for 2–7/8 in. OD titanium drill pipe for short-radius drilling. An update on recent field experience with titanium drill pipe utilization invarious short radius drilling programs is provided as well. Introduction This program was undertaken in late 1996 with the objective to develop titanium drill pipe for short radius drilling applications. The pipe size selected for this development was 2–7/8 in. × 2.151 in. ID with 3–5/8 in. OD × 1–3/4 in. ID NC26 tool joints. The pipe body is dimensionally the same as API2–7/8 10.40 lb/ft steel pipe which is widely used. The NC26 tool joint is a good match for the pipe and is also commonly used. Titanium has five attributes that make it an attractive choice compared to steel for short radius drill pipe:*Titanium has a density of 0.160 lb/in3 compared to 0.283 lb/in3 for steel orit's about 43% lighter.*Titanium has an elastic modulus of 17 million psi compared to 30 million psifor steel or it is 57% as stiff as steel.*Titanium is more corrosion and erosion resistant than steel.*Titanium does not suffer corrosion fatigue. The fatigue performance in air issustained in the drilling environment.*Titanium pipe has a yield strength of 120,000 psi, which equates to a strength to weight ratio of 1.54 times that of S-135 steel pipe. Even though all these attributes contribute directly to the pipe's attractiveness for short radius drilling, the low modulus is the primary characteristic that gives titanium the advantage over steel. It is desirable inthe industry to drill through a radius of curvature of 50 feet or less and have a service life greater than 500,000 cycles.

Introduction Divinyl benzene co-polymer beads, better known as plastic beads, have been used for reducing torque and drag in conventional drilling operations for 17 years. Over the last four years, they have also been utilized to reduce friction in horizontal wells when drill pipe is not sliding at a fast enough rate, or is not moving at all. Co-polymer beads have also gained recognition as a means of reducing friction in coiled tubing workovers. Friction is reduced by introducing co-polymer beads between the drill string and bore hole. Laboratory testing and field experience have developed methods for reducing friction through specific application techniques. Application of the beads can vary, from spotting small "pills" in specific sections of the bore hole to carrying a concentration of beads throughout the system using a bead recovery unit. Drill string drag is the incremental force required to move pipe up or down in the hole, and torque is the force required to rotate pipe. The magnitudes of torque and drag are related in any particular well, and high drag forces and excessive torque loads normally occur together. There are a number of causes for excessive torque and drag. They include:tight hole conditions;sloughing hole;key seats;differential sticking;cuttings buildup because of poor hole cleaning; andsliding well bore friction. With the exception of sliding friction, these causes are associated with problem conditions in the well bore. Although all of these conditions can occur in horizontal wells, the primary source of torque and drag in a horizontal well with good hole conditions is sliding friction. The ability to alleviate sliding friction using co-polymer beads has proven to be extremely beneficial in horizontal drilling and workover operations, including standard pipe and coiled tubing. Sliding Friction Normal contact force and the coefficient of friction between contact surfaces are the two factors that affect sliding well bore friction. Another factor, capillary attraction, must be considered in open hole situations. Capillarity is described as the relative attraction of the molecules of a liquid where it is in contact with a solid. The relative attraction of molecules leads to a force of adhesion between a solid and a liquid. The wallcake of a well bore will exert very strong capillary attraction forces on a drill string when it comes in close contact with the drill string. This is explained by the fact that the wallcake or mudcake is composed of very small particles of clay, barite, sand, or other matter, and these minute particles will have considerably more surface area exposed for wetting by liquid than would larger particles in the same section of mudcake. The smaller the particles, the more surface area exposed for liquid wetting, thus the greater the attractive capillary force exerted. The capillary attractive force could lead to the drill string adhering to the wallcake, creating torque and drag. The beads, having a larger particle size than the solids in the wallcake, reduce this adhesive force.

With the increasing intensity of oil and gas field exploration and development, oil and gas wells are also drilling into deeper and more complex formations. Conventional steel drilling tools can no longer meet the requirements of ultra-deep, high-temperature and high-pressure wells. The paper first analyzes the advantages of titanium alloy drill pipe based on basic performance of titanium alloy drill pipe. The experimental results show that the basic properties of titanium alloy drill pipes meet the operating standards of the petroleum industry. Then the buckling performance of titanium alloy drill pipe and steel drill pipe is compared, the calculation results show that the buckling performance of titanium alloy drill tools is slightly lower than that of steel drill tools. Secondly, the maximum allowable buildup rate of titanium alloy drill pipe and steel drill tool is studied. The research shows that under the same condition of the drill pipe outer diameter, titanium alloy drill pipe can be used for a smaller curvature radius and greater buildup rate. This advantage of titanium alloy drill pipe makes it more suitable for short radius and ultra-short radius wells. Finally, taking a shale gas horizontal well as an example, with the goal of reducing drill string friction and ensuring drill string stability, a comparative study on the application of titanium alloy drill pipe and steel drill pipe is carried out. The results show that titanium alloy drill pipe has a wider application in the field, and is suitable for operations under various complex working conditions.

Harsh drilling conditions can exceed the capabilities of traditional drill string connections. As the petroleum industry moves toward more severe drilling applications - deepwater, extended reach, high-angle, short-radius and ultra-deep wells - new drill string connection designs are required to safely and efficiently achieve the drilling objectives of these projects. This paper describes three new rotary shoulder connections that provide significant operational advantages for extreme drilling applications. Introduction An advanced, high-performance tool joint design provides approximately 70% more working torque capacity than standard API connections. This new design is a second-generation, double-shoulder connection that is optimized for each drill pipe size. The connection's increased torsional strength allows for the use of a streamlined tool joint configuration. The connections can be configured with a smaller OD and larger ID compared to standard API connections without sacrificing torsional capacity. A second version of this connection incorporates a radial metal-to-metal internal pressure seal. This connection provides high torsional strength combined with gas-tight pressure sealing capability. Drill strings with the gas-tight connection can be used for drill stem testing (DST) operations, underbalanced drilling and high-pressure workover and completion operations. This eliminates the need for a separate work string saving time, money, rig space and set back capacity. This is a significant advantage in offshore operations where rig space and set back capacity are at a premium. A third development discussed in the paper is a new thread form that provides increased durability and improved fatigue life compared to standard API connections. This thread form has been successfully used on drill pipe pins and drill collar boxes. This paper discusses the engineering philosophy behind each of these new designs and details results of physical testing. Applications where the connections have been used are also presented. Design Configuration and Capabilities The eXtreme™ Torque (XT™) is a second-generation double-shoulder connection (see Figure 1). The XT design evolved from the design of the HI TORQUE (HT™) connection. Figure 2 depicts the make-up characteristics of XT and HT. Both connections spin up freely from the stab-in to hand-tight position. In the hand-tight position the primary external shoulder makes contact. As the connection is made-up from the hand-tight to power-tight position the box counterbore compresses and the pin base elongates elastically and the secondary torque stop engages. The secondary torque shoulder provides the increased torsional capacity compared to a standard API rotary shoulder connection. The external (primary) shoulder is the pressure seal for the connection just as on an API connection. Since the secondary shoulder functions solely as a torque stop and not a pressure seal, minor damage to the secondary shoulder can be tolerated without adversely effecting connection performance provided there is no protruding metal that will impede contact between the shoulder surfaces. Any protruding metal on the secondary shoulder must be removed with a file or abrasive paper. Use of thread protectors when the pipe is racked back in the derrick is not required or recommended.

Industry advances continue to enable pursuit of more challenging drilling targets with complex well bore trajectories. Many of these targets are in costly deepwater and/or remote operating areas. Demand for a practical, field-proven drill pipe fatigue management system has grown as drill string failures due to fatigue contribute to a significant amount of non-productive time and cost. The response to this demand has been the development of an engineered approach that combines pipe section positioning and inspection scheduling based on estimated fatigue damage rather than rotating hours or footage drilled. Successful real-time field implementation with ongoing drilling programs demonstrates that the cumulative fatigue damage technique is a valuable and proven tool for risk mitigation and cost reduction. The cumulative fatigue damage technique and its implementation have been introduced in previous literature [1,3,8,10]. This method of monitoring fatigue damage due to rotary operations allows the pipe to be evaluated under real-time operating conditions along a specific section or the entire length of the drill pipe. Monitoring begins at spud and is performed on each joint of drill pipe as it traverses along the well path to total depth (TD). This not only allows a quantitative measure of the relative fatigue damage accumulated joint by joint for the drill pipe, but also provides the opportunity to manage logistics, forecast pipe inspections and position pipe sections to minimize cumulative drill string fatigue damage. The cumulative fatigue damage technique has been successfully applied in the field[1,10]. Hind casting, pre-drill planning and real-time analyses have been utilized for assessing drill string design as well as pipe management. The current case study further demonstrates the methodology introduced in the previous literature and illustrates the modeling and management of fatigue damage over a three well project. The subject operator originally anticipated that pipe inspection may be required before each well to mitigate costly historical drill pipe failures. However, the cost and logistical challenges of mid-program pipe inspection in remote operations could not be ignored. Described is the pipe management strategy employed to complete the drilling program without drill pipe failures and without the need for any mid-program inspections. In addition, the inspection results post TD of the third programmed well have been evaluated and correlated back to expected pipe damage, making this an excellent case study for the further deployment of this technology.

During the drilling process, horizontal drill strings are often subject to stick-slip and back-pressure phenomena, which undermine drilling safety and affect drilling costs. However, most of the models proposed in the existing literature apply only to the analysis of the drill string motion state and are irrelevant to the rotary drilling process in coal mines. This paper presents a lumped-mass model of a drill string in a horizontal coal mine well. First, based on reasonable assumptions, the drill-string system was considered as four lumped-mass units. The lateral-torsional dynamics model was established based on the Lagrange dynamics theory. Further, combined with lateral movement, the intermittent contact between the drill string and borehole wall is described, and the friction torque due to this intermittent contact is calculated. Combined with the Karnopp bit-rock interaction, a drill-string dynamics model of horizontal wells that considers intermittent contact friction was developed. The proposed horizontal well drill-string model is more suitable for rotary drilling in a coal mine, and the nonlinear influencing factors are considered more comprehensive.

Torsional vibrations experienced by drill strings can be detrimental to drilling operations. With a goal of understanding torsional vibrations experienced by drill strings and determining means to attenuate undesired vibrations, the authors have studied the effect of adding a sinusoidal modulation to a constant rotation speed of a drill string. A combination of modeling, analysis, and experiments is used to explore the influence of this rotation input modulation on the system response. The drill string is modeled as a modified Jeffcott rotor, which is described by a system with three degrees of freedom. Considering the case of forward whirling of a rotor in continuous contact with a stator, the equations of motion are reduced to a single degree-of-freedom nonlinear oscillator describing the torsional motions. In order to understand the fast time scale and slow time scale components of the motion, the method of direct partitions of motions is used to determine an approximate response to the nonlinear oscillator. The obtained results of the analysis illustrate that with the sinusoidal modulation of the rotor drive speed, the equivalent torsion stiffness can be enhanced and the character of the friction force at the contact can be made smooth. The analyses helps bring forth the stabilizing influence of the added sinusoidal input to the rotor drive speed. Over the considered parameter ranges, the numerical results obtained with the full three degree-of-freedom model and the reduced single degree-of-freedom model are found to be in agreement with each other. Furthermore, the results from these models are found to compare well with those obtained by using the method of direct partition of motions. Experiments with a laboratory scale drill-string arrangement are to be carried out to validate the analytical and numerical findings and further explore the effectiveness of the drive speed modulation on the rotor dynamics. Introduction Slender rotating structures are used in many engineering applications. Drill strings are long rotating slender structures, which are used in drilling operations. A schematic of a rotary drill rig is shown in Fig. 1 (e.g., Liao, Balachandran, Karkoub, and Abdel-Magid, 2011). Drill strings experience different types of vibrations (axial, torsional, and lateral vibrations) that may lead to detrimental failures of a drilling system. Drill-string vibrations have attracted the attention of many researchers, and many models have been developed to understand them. Since drill strings have a large length-to-diameter ratio, typically, the first torsional natural frequency and first lateral natural frequency are close to each other. This frequency proximity and the nature of the system allows for coupling and energy transfer between the associated vibration modes. Here, as a step towards developing further understanding, a drill string is modeled as an extended planar Jeffcott rotor with gravity acting normal to the rotor. Due to the planar motions, no gyroscopic effects are considered. The extended model, which was earlier considered in the work of Vlajic, Liu, Karki, and Balachandran (2014), is shown in Fig. 2. The model is described with three degrees of freedom (DOF), namely, x and y to account for lateral motions, and theta to account for torsional motion. A large number of research efforts have focused on controlling drill-string vibrations by using different feedback control algorithms, which need measurements along the drill string. In this work, the authors propose a different control approach to mitigate whirling motions during continuous rotor-stator contact. This can be compared to a situation of a drill string being in continuous contact with the borehole. The approach is open loop in implementation and this approach is based on adding a high frequency input to the drive speed of the drill string. Given the open-loop nature, the method does not depend on any measurements along the drill string or rotary table, which could be attractive for a practical stand point. Although the current focus is on motions of a rotor with continuous stator contact, it is planned to study stick-slip and non-contact cases in the future. System Modeling, Studies, and Results As previously mentioned, the drill string is modelled as a Jeffcott rotor with three DOF. Proceeding along the lines of the group's prior work (Vlajic, Liu, Karki, and Balachandran, 2014), after some approximations for the continuous rotor-stator contact case, the 3 DOF system is reduced to a single second-order nonlinear differential equation governing the torsional motion. In Fig. 3, for a representative case with a constant drive speed, the torsional state histories obtained for the full model and the reduced model are plotted. It is noted that the final state of the motion is captured quite well. To further analyze the response during forward whirling, the reduced-order model was nondimensionalized and an approximate solution was obtained by using the method of direct partitions. This method allows one to separate slow scale motions from fast scale motions. As discussed, in the group's prior work, this method can be useful to examine whirling motions. The results obtained by directly integrating the full model as well as the reduced-order model have been compared with that obtained by using the method of direct partitions of motions. It is seen that the perturbation analyses is able to provide an approximate solution that compares well with the numerical results obtained through direct integrations. Next, this analysis is used to examine the influence of the addition of secondary frequency component. It is seen that the addition of the secondary frequency, a high-frequency one, helps smooth out the friction coefficient variation with respect to the relative speed at contact. This is found to have a beneficial effect on the motion and helps suppress large-amplitude torsional motions. Stability analysis was also conducted to examine this effect. Concluding Remarks A study has been conducted to examine the influence of sinusoidal modulation of rotor drive speed in a system, wherein the rotor experiences continuous stator contact. A single degree of-freedom reduced model is developed to study the torsion response and it is found that the addition of a high frequency input can be beneficial in attenuating rotor motions. This is believed to be useful for developing open-loop control schemes for attenuating forward whirling motions of drill strings. Results obtained from a lab scale experimental arrangement will be used to examine the effect of this drive speed modulation further and they will be reported in the conference presentation. Future studies could build on the current effort to examine cases of backward whirling. Acknowledgment: The authors would like to gratefully acknowledge the support received from the Qatar National Research Fund for NPRP Project 7-083-2-041, to pursue this collaborative work between the University of Maryland, College Park, MD, USA and Qatar University, Doha, Qatar.

The vibration characteristics of drillstring with positive displacement motor in compound drilling Part1: Dynamical modelling and monitoring validation

This paper presents a method to simulate the circulating system while drilling a well. For any given pump rate the pressure losses through the surface system, down the drill pipe, through the bit, and up the annulus can be determined. The algorithm also has the capability of simulating a washout in the drill string, losing fluid to the formation, having fluid produced into the annulus, and fracturing the formation(s). The algorithm is general enough to calculate pressure losses for turbulent and laminar flow, simultaneously. This covers the situation where multiple flow regimes exist in the same circulation loop. Formulation of the algorithm is presented, showing how a network type of solution is used to calculate the pressures and flows. The iterative solution converges rapidly and can be used for real time and faster than real time simulation. Detailed surface pressure data was obtained from two wells in Texas. The circulation simulation program was used to calculate pressure losses at various depths in each well for a variety of circulation rates. Results presented in this paper show close agreement with the field data. To show the versatility of the simulation algorithm a series of idealized circulation system simulations are presented. These include various downhole circulation situations such as lost circulation, circulation without returns, and fluid production response as a function of permeability and pressure, and circulating with a hole in the drill string.

Erosion wear at the key point of a drill string is very severe in gas drilling. The investigation shows that failure of drill string is very serious in gas drilling. The probability of failure of the drill pipe and the drill collar is the highest in all the drill string, and the near placement of pin and box is often damaged. According to the investigation of drill string failure and erosion theory, the erosion model of drill string is established. The erosion rate at the key point of a drill string is solved using the Grant and Tabakoff formula. Different factors, such as gas injection volume, rate of penetration (ROP), cuttings' diameter, cuttings' shape factor, cuttings' number, and temperature of the annulus, are considered. The result shows that the erosion rate at the key point is more severe than that of other locations on the drill pipe. Because of higher peak stress for a drill string with eroded wear, there is a more serious effect on the residual strength of a drill string with eroded wear. Crack forms easily, due to severe erosive wear and deeper pits. Also, fracture failure of a drill string is caused by larger axial load and torque. In this paper, analysis of such influencing parameters as gas injection volume, ROP, cuttings' particle size, cuttings' shape factor, cuttings number and temperature of the annulus is conducted, among which gas injection volume, ROP and cuttings number are proven as the main controlling factors that affect the erosion wear at the key point of a drill pipe.