Drill String Failure Analysis and Erosion Wear Study at Key Point for Gas Drilling

Experimental and numerical study of drill pipe erosion wear in gas drilling

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.

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.

Stress Analysis on Drilling String Vibration in Gas Drilling

Drill string models are of two major types- Conventional and Periodic. Conventional drill string models are widely used due to their simplicity in manufacturing and dynamics analysis. Drill strings are affected mainly by torsional, lateral and axial vibrations. The dispersive or propagative nature of these vibrations can only be analyzed by using periodic drill string models. Drill pipe makes up the majority of the drill string. In reality, at each end of the drill pipe, tubular, larger-diameter portions called the tool joints are located. Since the dimensions of the tool joint are negligible when compared to the drill pipe, conventional drill string models assume drill strings to be uniform structures. The tool joints in drill strings introduce a geometrical periodicity in the structure.A periodic structural component is comprised of a repeating array of cells, which are themselves an assembly of elements. The elements may have differing material properties as well as geometric variations. The periodic structures act as mechanical filters for the wave propagation. A material or geometrical change in the structure causes a disruption to the continuous propagation of vibration waves.There are three types of waves propagating in rotating structures: torsional, flexural (bending) and longitudinal. Of these waves, torsional and longitudinal waves are dispersive while flexural waves are non- dispersive. The proportions of the waves which are dispersed vary according to the Wavenumber. The wavenumber is a property of the wave and depends on the structural, material and geometrical properties of the wave guide. Waveguide is the medium through which a wave travels. The wave number, and hence the dispersion and propagation characteristics of waves can be tuned by varying the material and geometrical periodicity in the drill strings.This paper presents the vibration propagation and attenuation characteristics in conventional and periodic drill string models. The periodic drill string model is developed such that it can be easily scaled to a real drilling rig model. The research also features a laboratory setting which comprises a mini drilling rig and actual drilling samples. These features ensure robustness of the dynamics analyzed for the periodic drill string model.The research findings are analyzed under zero and non- zero borehole drill string interactions. Vibration information is collected from upper and lower parts of the drill string models to compare the propagation and attenuation characteristics. Proximity sensors are used for the data acquisition which is then analyzed using frequency and power spectrum graphs. The time and frequency domain vibration propagation characteristics are investigated for both the conventional and periodic drill string models. Laboratory testing analyzes (1) introduction of stop and pass band regions in frequency spectra by periodic drill string models, and (2) vibration attenuation in torsional and lateral vibration modes. The tests confirm the introduction of stop bands in frequency spectra for the periodic drill strings, while they were absent and had an all pass-band for conventional drill string models.The research opens up a new method of passive control of drilling vibrations- by introducing tool joint designs which could be tuned to efficiently dampen out the harmful vibrations affecting the drilling rigs.

This paper attempts to explain the motion behaviour of the marine riser coupled to a drill string when the vortex induced vibration (VIV) is involved. Vibrations have been reported to have a major effect on the drilling performance, affecting the rate of penetration (ROP), causing severe damages to the drilling tools and also reduces the efficiency of the drilling process. There are two major components of drilling tools that are subjected to vibration, namely the marine riser and the drilling string. Analysis of vibration in the marine riser and drill string are two topical areas that have individually received considerable attention by researchers in the past. Though these two subjects are interrelated, borne by the fact that the marine riser encapsulates and protects the drill pipe, there have been few attempts to investigate them together as a unity. Due to the complexities of the models, simplified assumptions were made in order to undertake the investigation by using staggered approach. The results were compared with the experimental and simulation data from the open literature. It was found that the maximum displacement with negative damping occurs at low frequency and rotation speed.

A model for predicting sand erosion in 90 degree elbows and bends has been developed based on computational fluid dynamics (CFD), particle tracking and erosion data. After the flow field was obtained from the flow (CFD) model, particles were introduced into the flow and particle trajectories were computed using a Lagrangian approach. A model was also implemented that accounts for the interaction between the particles and the target material. Based on predicted particle impingement velocities, erosion rates and penetration rates were predicted using the empirical equations for erosion ratio. The predicted penetration rates are compared with available experimental data for several different elbows. The agreement between the predicted penetration rates and the experimental data is good. The erosion model is applied to standard (short-radius) elbows and long-radius elbows to understand why long radius elbows have lower erosion (penetration) rates. In addition, based on many predictions and erosion rate results, a new CFD based correlation is developed and is recommended as a first-order approximation for engineering calculations to account for effects of elbow radius on erosion in long-radius elbows. This equation is for computing the ratio of the wall thickness loss (or the penetration rate) in a long-radius elbow to the penetration rate of a standard (short-radius) elbow. The results from the correlation agree well with the trend of available data in the literature.

On the basis of the study on drill string vibration rules in vertical well drilling and the idea of transformation of drill string vibration energy to drilling fluid hydraulic energy, a novel tool, down-hole drill string absorption & hydraulic supercharging device (DSAHSD), is designed to further improve the rate of penetration (ROP). The DSAHSD combines the advantages of reducing the axial vibration of the drill string and generating more than 120 MPa ultra-high pressure jet to effectively assist rock breaking. When the drilling fluid flows through this tool, part of the drilling fluid will be modulated to the ultra-high pressure jet by periodic compression of piston drove by drill string vibration. During this process, the ultra-high pressure jet ejected through ultra-high pressure nozzle that fixed on the bit edge in bottom hole. Because of hydraulic auxiliary rock breaking of the ultra-high pressure jet, the ROP will be improved. This tool has been applied to more than 40 wells in four oil fields throughout China. The results show that the maximum density of the test drilling fluid is 1.9g/cm3, the maximum footage is 1480m, and the operation time of the tool is more than 200 hours. Furthermore, the average ROP was increased by approximately 11% to 831%. In conclusion, the DSAHSD has the characteristics of a simple structure, has a long lifetime, is able to adapt well with existing drilling equipment, and can provide a safe and efficient drilling technique for deep wells. In addition, a novel design idea of down-hole hydraulic booster was proposed, so this is a major breakthrough of down-hole supercharging technique.

Improvements in horizontal drilling technology made it possible to drill almost in all types and shapes of reservoirs. No change, however, was made in the design of drill pipes to overcome the high stresses especially for drill pipe rotating in medium or short radius horizontal wells. During drilling of some horizontal wells in the Middle East area, an abnormal amount of tubular failure was noticed in the drill string being used. This paper presents a field case study of drill string failure during drilling of medium radius horizontal wells. Investigations as well as a metallurgical evaluation were conducted in an attempt to establish the possible causes of the drill string failures. Other possible reasons for drill string failures and suggestions to minimize the bending stress of drill pipes are also discussed.

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.

Vibrations are known as destructive loads and thus are leading to downhole fatigue failures, severe bottom hole assembly and bit wear and may cause wellbore instabilities. Downhole measurement of vibrations, however, can provide valuable information about downhole conditions and characteristics of the formations drilled. Uniaxial compressive strength is one of the representative characteristics of rock properties. It shows the capacity of a rock to withstand a certain amount of axial loads. Optimizing weight on bit and rotary speed of the drill string are the ways to continue drilling a hole - of course by exceeding uniaxial compressive strength of formations - and to keep rate of penetration in an optimal range during drilling operations. Therefore, it is expected that the axial vibrations change with variations of the uniaxial compressive strength of formations. Previous experiments with several layered concretes cubes proved that the drill string vibrations are related to the uniaxial compressive strength of concretes. To extend the study in this area, complex rock samples such as sandstone, dolomite and limestone were drilled with optimized ranges of weight on bit and rotary speed of drill string. Experimental drilling operations were conducted using a laboratory drilling rig (CDC miniRig) with a vibration sensor sub attached to the drill string. The uniaxial compressive strength of all samples was measured prior to the experiments. During all experiments, drilling parameters were recorded with a sampling rate of one second and the vibration data with a sampling frequency of 3200 Hz. Analysis of magnitude and higher order frequency moments of vibration data in combination with the mechanical specific energy demonstrated a change of the drill string's axial vibration measurements due to variations of uniaxial compressive strength. From that it is concluded that the formations can be recognized in real-time by incorporation of the vibration measurements. Introduction When talking about drill string vibrations, in most of the time downhole fatigue failure, severe bit wear and reduced rate of penetration come to the mind. Drill string vibrations are inevitable in the drilling operations and lots of researches have been investigated to manage the magnitude of vibrations by designing proper bottom hole assemblies (Macpherson et al., 1993; Chen et al., 2006). However, the vibrations can be utilized as a valuable tool to recognize formations drilled. In most of the cases, the vibrations are caused by bit and drill string interaction with the formations under certain drilling conditions. One of the dominant conditions is formation characteristics (mechanical and petrophysical properties). Uniaxial compressive strength (UCS) is one of the representative characteristic of the formation properties. It shows the capacity of a formation to withstand a certain amount of axial loads. Previous works show that the harder the formation, the bigger the magnitude of the vibrations and vice versa (Esmaeili et. al, 2012). Therefore monitoring vibrations in real-time can advance warning of formation changes. Myers et al. (2002) explained how the vibration data measured by an accelerometer are related to petrophysical properties of the formations in the Indian Ocean region. Al-Shuker et. al. (2011) presented changes in drilling dynamics driven by the bit's interaction with the formation can be a near instantaneous indicator of changes in formation characteristics. The key is real-time drilling dynamic measurement at the bit. Previous works (Esmaeili et al., 2012) presented a close relationship between the mechanical properties of layered concretes cubes and the measured vibrations. The study proved that the vibrations can be used as a tool to recognize the formation changes.

A heavy, stiff-bottom drill collar can substantially improve deviation performance, theoretically increasing penetration rates by 50 to 100 percent in deviation-prone areas. The theory, performance characteristics, and experience in fabricating and field testing two depleted-uranium alloy heavy metal collars are detailed. Introduction Reducing the weight on bit provides one of the major techniques for controlling or reducing hole angle. This results in lower penetration rates and increased drilling costs. In both straight holes in deviation-prone areas and in directional wells, the cost of deviation control can become a major portion of the total drilling cost, particularly in areas of high rig cost. particularly in areas of high rig cost. This paper presents a method for theoretically increasing penetration rates by 50 to 100 percent when drilling in deviation-prone areas where the weight response is reasonably linear. By using a heavy, stiff bottom collar, the deviation performance of the drillstring can be improved substantially. As is illustrated in Fig. 1, the addition of a heavy metal collar to the drill-collar string allows more weight to be applied to the bit while maintaining the same hole angle. The paper develops the underlying theory that shows how a heavy metal collar can be used to advantage in deviation control. The theory is used to develop practical charts on the performance characteristics of heavy metal drill-collar performance characteristics of heavy metal drill-collar strings for use in selecting suitable hookups. The paper concludes by detailing Shell Development Co.'s experience in fabricating and field testing two heavy metal collars made from a depleted-uranium alloy. Hole Deviation Mechanics The combination of drill-bit/rock interaction and drillstring mechanics that controls hole deviation has been discussed in detail. A principal concern of hole-deviation mechanics is to develop techniques to maximize weight on bit for faster drilling while controlling hole deviation. The tendency for increasing hole deviation with increased weight on bit must be resisted by increased lateral force on the bit. This lateral force is supplied by the pendulum behavior of the drill collars. The longer the pendulum length and the heavier the pendulum, the higher the lateral force will be to resist deviation. Pendulum length and weight increase with drill-collar stiffness and density. The effect of drill-collar density and stiffness on deviation performance can be illustrated by the three cases shown in Fig. 2. The first case, shown for comparison, is an unstabilized 8-in.-diameter steel drill-collar string in a 5 degrees, 12 1/4-in. -diameter hole. The second case is identical to the first (in size and weight per foot), except the collar stiffness is reduced to the stiffness of a 6 1/4-in.-diameter collar string. The final case shows the effect of replacing the bottom steel drill collar with a drill collar made of a heavier material, such as depleted uranium. Notice that, to maintain the same drilling conditions with the more flexible drillstring, the weight on bit must be reduced by 20 percent for the condition shown. Conversely, by using the heavier drillstring. the weight on bit can be increased 60 percent in this example, resulting in a corresponding increase in the penetration rate. Heavy metals structurally suitable for drill-collar service are much more expensive per unit volume than steel. JPT P. 521

An Engineered Geothermal System (EGS) pilot project was commissioned to prove the economic viability of an industrial scale geothermal heat plant in Finland. The project aims to generate 40 MW of emission free heat energy, supplying up to 10% of the city of Espoo’s district heating needs. Two wells of 6400 m MD and 6213 m MD (measured depth) were drilled through formations of hard, abrasive granitic gneiss with maximum measured 560 MPa UCS (unconfined compressive strength). Typical dull conditions of lost and worn cutting structure and gauge diameter wear of between 3/16-in to ¼-in contributed to excessive torque, stuck incidences, low rate of penetration (ROP) and difficulties achieving build rate. To address these drilling challenges, this paper explores the interplay between new cemented carbide compact technology, drill bit design, and drilling parameter road mapping. The directional section of the first well was drilled with an average ROP below 2 m/hr and run length averaging 56 m per bit. The well took 246 drilling days and 44 BHAs (bottom hole assemblies) to achieve TD (total depth). Between the first and second well an application specific drill bit design package and step-wise parameter program were implemented. Design enhancements included improved gauge protection, bit hydraulics for minimizing cone erosion and subsequent TCI (tungsten carbide insert) compact loss. Novel hybrid TCI materials technology was introduced having a 100% improvement in wear resistance and durability as compared with conventional grades, to drill these hard and abrasive granitic formations. New BHAs and drilling plan were selected based on the bit design selection to reduce wear on BHA components, improve directional control and reducing drilling dysfunctions. Once these factors were under control, a low risk approach to extending the bit revolution limits (krev) for the roller cone sealed bearings could be implemented based on downhole parameters and previous bit dulls, leading to longer run lengths. The combination of bit design and material enhancements with a properly selected BHA and drill plan increased run lengths and ROP. The second well’s 8.5-in directional section was drilled with a 13% increase in average ROP and a 69% increase in average run length without exceeding krev limits. Well on well, a 77 day reduction in AFE (authorization for expenditure) was realized. We demonstrated the combination of oil and gas bit and BHA design, drilling plan, and new cutting material capabilities can reduce EGS well construction costs in order to make these renewable energy sources economical.

Government of India has set an ambitious target of reducing hydrocarbon import. Increasing oil & gas production is one of the measures by which oil & gas import dependency can be reduced. Despite relatively low crude prices globally, substantial E&P activities have been carried out in the country in the last decade, which has witnessed an exponential increase in exploration of oil and gas reserves. Many new fields were discovered during this exploration campaign out of which, few are potential traps containing hydrocarbons. Kutch and Saurashtra Basin off Gujarat coast is one of the exploration fields that involves trap drilling to explore reservoir sands below. Recently for the very first time, in a decade, oil reserves have been discovered in prospective sedimentary basin of Saurashtra. (DGH India Outlook, 2017-18) Drilling in this basin is characterized by slow rate of penetration (ROP), frequent bit trips, drill string failure, and high well cost. The 12 1/4-in section in this offshore block typically drills through very hard, abrasive and thick layers of Basaltic formation (known as Deccan Trap) with unconfined compressive strength (UCS) between 18-42 kpsi. Conventional polycrystalline diamond compact (PDC) bits and roller cone (RC) bits faced extreme cutting structure damage and delivered poor ROPs in this section. In this paper, challenges of drilling approximately 2,200 m of hard and abrasive Deccan Trap in the 12.25-in section is discussed along with a proposed solution of hybrid bit design by combining conical (CDE) and ridged (RDE) diamond elements. Two new hybrid 8-bladed 16-mm bit were specifically designed for this application. The first bit drilled an interval of 952m with an average ROP of 1.9m/hr and the second bit drilled an interval of 960m with an average ROP of 1.83m/hr. Both the bits came out of the hole in good condition, thereby delivering a benchmark performance in drilling this challenging section. The runs resulted in 40% reduction in cost/meter for this section and saved 36 offshore days for the customer.

During the drilling process, the whirling motion often occurs, which will cause the drill string to vibrate violently, accelerate the fatigue damage of the drill string, and eventually cause the bottom hole assembly to fail. But the existing research rarely focuses on the critical whirling velocity of drill string. To solve this problem, the whirl differential equation of drill string was set up based on the D’Alembert principle, and the critical whirling speed equation of drill string was deduced according to separation variable method. Reference to actual downhole conditions, the influence of drill stem wall thickness, tension, drilling depth, drilling fluid flow rate, and other factors on the critical whirling speed of drill string are considered. Research results indicate that when n ≤ 8324, drill string has a critical whirling speed, and when n > 8324, there is no critical whirling speed. And under different orders, as drill string wall thickness and drilling depth increase, the critical whirling velocity decreases. In general, the drill string rotation rate is 0–150 rad/min. When the drilling depth is 0–500 m, the critical speed is not considered. However, as drilling depth exceeds 500 m, the critical whirling velocity is within the general range of drill string speed. Therefore, drill string velocity should be chosen reasonably to avoid resonance. When the tension increases, critical whirling velocity increases. As the drilling fluid flow rate increases, the critical whirling velocity of drill string decreases. But when drilling fluid velocity is close to 120 L·s−1, increasing the drilling fluid velocity hardly affects the critical whirling velocity of drill string. In a word, research results of this paper have certain guiding significance to drilling engineering.