Recent Advances in Casing Wear Technology

During drilling operations, there is contact between the tool joints (TJs) of the drilling string and the well casing. This interaction, which occurs in the presence of drilling fluid and abrasive particles detached from the well walls, can lead to excessive wear of these components. In the case of the casing, this wear is known as casing wear (CW), a phenomenon that has been a continuous concern in the development of oil and gas fields. This is because CW is related to implementation costs and has the potential to lead to catastrophic outcomes if it results in ruptures or well collapse (Thomas, 2001). To reduce casing wear and prolong the lifespan of TJs, hardbandings are deposited on the latter. However, hardbandings are typically made of ferrous alloys, containing hard phases in their microstructure (carbides and/or borides) (Cernocky and Paslay, 1990), and it is crucial in the material selection to balance between the protection offered to the TJ (which should be high) and the wear generated on the casing by the hardbandings (which should be low). Furthermore, challenges lie in controlling field variables and the time needed to assess wear conditions. These factors may result in longer decision-making processes crucial for the industry. Given these factors, there is a possibility to develop, in a laboratory environment, a full-scale test condition that can experimentally study material wear, based on controlling variables and utilizing accelerated testing parameters. However, such a full-scale setup requires greater financial investments, primarily due to equipment development, specialized labor, physical space, and in some cases, the use of full-sized test pieces. Therefore, despite its validity, this experimental study condition may not always be attractive. A second option often employed in laboratory studies involves conducting tests at a reduced scale, which significantly narrows down and controls the parameters influencing wear, making this test condition valid and practical for obtaining faster and more accurate results. Therefore, the study of CW, especially through experimental testing, is relevant to the industry as predicting casing wear is crucial to ensure well integrity. In this context, this work will present the steps for the development and qualitative validation of the reduced-scale test based on the full-scale API 7CW test. The qualitative test comparison aims to compare the wear factor (WF) curve behavior over time in a way that develops an accessible, fast testing methodology capable of ranking materials and severe abrasive wear conditions. The aim of this work is not to develop a test that replaces the one proposed by the API 7CW standard, considering the importance of obtaining quantitative parameters closer to field conditions inherent to the full-scale test conditions. Thus, this work proposes the development of an accelerated testing methodology for conditions proposed by the API 7CW standard that allows, in a practical way, the selection of materials and the evaluation of different severe wear testing conditions.

ABSTRACT: In the process of exploration and development of extended-reach wells and ultra-deep wells, serious dogleg severity and high hardness formation, etc. will lead to casing exterior wear, thereby reducing the residual strength of the casing. However, the existing research on casing wear mainly studies the interior wear of casing caused by the rotation of drill pipe joints, and ignores the exterior wear caused by the contact between casing and well wall during casing running. As a consequence, the prediction model of casing exterior wear is established based on the wear efficiency model and the three-dimensional torque and drag model. Case study is conducted with this model and sensitivity analysis is also performed. The results show that the casing with the greatest exterior wear depth is located below the direction turning section. The wear depth decreases with the increase of the outer radius of the casing, and increases with the increase of the wellbore radius. In addition, with the increase of drilling fluid density, the wear depth of the upper casing increases, and the wear depth of the lower casing decreases. The casing collapse resistance after casing exterior wear is studied through numerical simulation. The results show that the collapse resistance of casing decreases with the increase of wear depth, and there is an approximate linear relationship between the two. The study provides a method to improve the prediction accuracy of casing wear, which is of great significance for the casing design and wellbore integrity. 1. INTRODUCTION With the development of drilling technology, horizontal well and extended reach technologies are widely used in the world. The wellbore conditions of extended-reach wells and horizontal wells with long horizontal sections are more complicated than conventional wells. Running casing is challenging due to the difficulty of hole cleaning, the high friction factor, the wellbore tortuosity, and the large lateral force acting on the wellbore by the casing, etc. Usually the casing needs to be picked-up and released many times, and the running time is long, so the outer wall of the casing is more likely to be worn, which reduces the residual strength of the casing.

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.

We discuss the effect of casing wear on squeeze resistance and corrosion life. We analyze methods for prediction of casing wear and propose a new method. Providing that the length of the drill pipe (tool) joint is known, the main factors determining casing wear are the wear factor, the surface kiss (tangential) pressure, and the movement distance, where the contact pressure depends on the kiss pressure and contact arc length. The proposed model describes the experimental data more accurately than other known models.

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.

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.

The aim of the present paper is to set up a method for enhancing the casing design with emphases on the intermediate casing or liners, regarding the wear of the casing wall, which is appearing while drilling the subsequent horizontal production hole. By using this method, the well designer has the opportunity to prepare a “working envelope” in such a way that the further considerations as the well trajectory, dog leg severities, drilling parameters, type of mud, tool join geometry, should keep the casing wear in within technological limits imposed by the oil and gas operator, in order to maintain the intermediate casing ( liner) integrity and do not diminish or affect at least the upcoming well stimulation programs, and well control measures. More than this, by using this method, the well trajectory can be optimized from the begging in such a way that the lateral forces on tool joints to be full as per recommendations of API RP7G [1], so increasing the safe work of the drilling string bellow the fatigue stress limits.

Many modern well construction techniques have been developed with an eye toward drilling deeper, longer, and more cost effective Extended Reach Drilling (ERD) wells. One notable technology that has contributed to this effort is solid expandable tubulars. This technology was developed specifically to allow additional casing strings to be run to cover up problem zones and facilitate drilling the well to the ERD target. Solid expanable tubulars also help to reduce the overall resources required to construct the well. Projections show that using them would significantly reduce the size or volume, as well as the cost of the rig, the drill string, the bits, the cement, and, of course, the casing, resulting in lower overall costs. This result has been born out in practice and will culminate in the single-diameter well described elsewhere.1 The effects on ERD wells will be substantial, but there are important ‘side effects’ that can have a profound cumulative effect. The torque and drag on an ERD well is usually the limiting factor in the actual reach possible. These limits are mitigated by drilling fluid properties and the use of rotary steerable drilling tools among other technologies. Torque and drag are primarily influenced by geometric conditions like dogleg severity (DLS) and casing open hole size vs. drill string size, surface effects (commonly grouped together and named the friction factor), and drill string dynamic conditions (such as axial and rotary motion that overcomes the friction). The use of solid expandables has two distinct effects that can be favorable for the drilling of ERD wells. An important effect is that more favorable drill string casing geometry is possible and can reduce the tendency for helical buckling or drill string lockup. Another important impact is the ability to use larger drilling tubulars. This paper will examine data supporting the positive effect of solid expandable tubulars on drill string torque and drag. Data modeled for an ERD well shows the theoretical drilling limit improvement from these effects in real example wells. Extended reach drilling limitations have been pushed out significantly in recent times. Advances in mud systems, geomechanics, and the advent of rotary steerable systems have significantly improved the ability to reach further to access hydrocarbons. However, limitations, though receding, still exist. To counter them, new approaches are being developed that attack in various ways the traditional boundaries of extended reach drilling applications.

The longitudinal vibration of the bottom drill string is violent and the law is complex during the deep well drilling. The vibration of the drill string brings many adverse effects on the drilling pipe fracture and bit trampoling. Generally speaking, the effective way to control the vibration of drill string is to install damping device in bottom hole. The research group proposes a device that uses the longitudinal vibration energy of the deep well drill string to modulate the impact dynamic load, which converts the vibration energy of the downhole drill string that is not conducive to drilling into the mechanical impact energy that improves the rock breaking capacity of the bit. The impact load modulation device can use the drill string to apply the “mechanical WOB” and the differential pressure between the upper and lower piston to produce the “hydraulic WOB”, The simulation results show that the adjustable range of output load is 2 ~ 7T, and the change of each time is about 2T. The modulation law of impact load under the influence of longitudinal vibration of drill string and different parameters is analyzed. Through ground experiment and simulation, the damping performance and speed-up effect of the modulation device are compared and analyzed, and the impact load output characteristics of the device are analyzed, which provides a thinking for the design of damping and pressurization tools.

Deep wells are commonly drilled while steering the drill bit. The steering process is completely controlled by the drilling-rig operator. A key element of this procedure is the measurement and communication of navigation information from the bottom of the well to the operator. Pressure pulses modulated onto the flow of the drill fluid are now employed in some cases to communicate this information. However, data rates are only a few binary bits per second with this method. This drastically limits the quantity of data available to the operator. As an alternative method, elastic waves generated within the steel drill string can be used as a carrier signal to transmit data. The drill string is commonly assembled from 10-m segments of threaded pipe and forms a periodic structure. The elastic wavelengths of interest are shorter than this periodic length. Consequently, these waves undergo significant dispersion. This paper presents new data for the propagation of elastic waves in a 2-km drill string. The influence of aperiodicity in the drill string, rotation of the drill string, and noise levels are studied in detail. The data verify a method for reducing the attenuation of a carrier signal by a factor of 2.

Analysis has demonstrated a viable data transmission system for communicating by acoustical carrier waves in drill strings used to drill wells. Because of the periodic structure of this waveguide, complex transmission characteristics exist. Two experiments have been used to study these phenomena. In the first experiment, a scale laboratory model was constructed to examine the acoustical response of this system. A longitudinal impulse was produced with a hammer and the resulting signal was measured at several locations with semiconductor strain gauges. In the second experiment, the impulse response of a 1500‐ft drill string suspended in a mudfilled well was tested. The data exhibit all of the phenomena predicted by the theory. Measured attenuation is about 2 dB per thousand feet. Both the comb filter phenomena produced by the periodic structure of the pipe and tool joints, and the standing‐wave interference pattern caused by echos between opposite ends of the drill string are present. [This work was supported by the U. S. Department of Energy at Sandia National Laboratories under Contract DE‐AC04‐76DP00789.]

In Part 1, the Engineering Simulator for Drilling (ESD) is described, explaining the overall design, the engineering algorithms, the use of the interactive graphics, and the software and hardware used to create and operate any drilling system. Part 2 presents how the ESD is designed as a tool for the drilling person, giving the person the flexibility to use the ESD as a drilling time and cost analysis tool, or for well planning, or a full engineering simulator. A stand alone capability to use parts of the ESD for real time drilling analysis is also possible. An example of how a drilling person would use the ESD to build a drilling system is given. This includes logging onto the ESD, selecting the drilling location and geology, selecting the drilling rig, the initiation of the wellbore and the design of the mud system and the drill string. A description is given of how the user can operate the newly created drilling system, describing some of the options available to him. All Figures are actual photographs or plots of the various ESD graphic's pictures and menus.

A comprehensive analysis on the longitudinal fracture in the tool joints of drill pipes

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.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112872, "Trapped Annular Pressure Mitigation: A Spacer Fluid That Shrinks - Update," by B. Bloys, SPE, M. Gonzalez, SPE, J. Lofton, R. Carpenter, SPE, S. Azar, SPE, D. Williams, J. McKenzie, SPE, and J. Capo, SPE, Chevron; R. Hermes, Los Alamos National Laboratory; R. Bland, SPE, R. Foley, SPE, and F. Harvey, SPE, Baker Hughes; J. Daniel, F. Billings, and I. Robinson, Lucite International; and M. Allison, Flow Process Technologies, originally prepared for the 2008 SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed. In subsea-completed wells, fluids commonly are trapped in casing annuli above the top of cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced fluids, thermal expansion can create very high pressures and cause the collapse of casing and tubing strings. A successful field trial has been conducted in a 9,800-ft-deep gas well of a water-based spacer fluid that upon heat-triggered polymerization shrinks 20%, mitigating trapped annular pressure (TAP). Introduction TAP, also called annular-pressure buildup, is caused by the thermal expansion of fluids trapped in casing annuli between the top of cement and the wellhead. The pressure buildup usually is a result of heat transfer from produced fluids or from hot drilling fluids circulated while drilling a high-pressure/high-temperature well The pressure can exceed the collapse strength of the casing and production tubing. In land wells, the pressure is relieved easily by bleeding off some fluid through a casinghead valve. In subsea-completed wells, wellheads are much less accessible and generally not fitted with the necessary valves. Perhaps the most successful mitigation approach has been the use of vacuum-insulated tubing (VIT). This technique generally has been successful in keeping the annular-fluid temperatures within an acceptable range. However, with the advent of deeper and hotter wells in deep water, the limits of the protection provided by VIT are being approached in two ways. First, deeper wells have much higher hanging weights that are reaching the stress limits of VIT designs. Second, the greater depths also are producing higher temperatures. Even with the insulating effects of VIT, the temperatures are sufficiently high that pressures are predicted to increase to unacceptable levels. A new approach created a water-based spacer fluid to be used just ahead of the cement. The spacer contains 10 to 30% emulsified liquid methyl methacrylate (MMA) monomer. The liquid MMA shrinks 20 vol% upon polymerizing. The polymerization is triggered by heat and an appropriate chemical initiator. MMA is emulsified into a simple water-based fluid that is intended to be the last spacer pumped just ahead of cement, filling most of the open annulus. The monomer has a low flash point similar to methanol, and it must be handled carefully but has a long record of safe industrial use.