The main objective of this study was to understand the impact high-resolution measurement-while-drilling (MWD) surveys have on casing standoff and mud removal simulations and its impact on final cement program design and risk analysis. High-resolution surveys use a combination of static and continuous MWD inclination data to characterize the well trajectory at 3-m (10-ft) intervals rather than the current industry practices at every stand; i.e., 30 m (100 ft). However, several case studies had demonstrated that surveying the well path at these intervals is often not sufficient to capture the true characterization of the well in question. This result, in some scenarios, leads to significant errors in the final reported dogleg severity (DLS) and tortuosity; therefore, resulting in optimistic well engineering simulations due the hidden additional tortuosity not applied in the models. Two North Sea wells were analyzed when using conventional trajectories defined at each drillstring stand as well as using high-resolution trajectories to evaluate the impact on casing centralization and mud removal simulations. The latest generation cementing software for placement simulation was used in this study. The simulation has the capabilities to deal with computing pipe standoff and angle direction in a 3D annulus, including gravitational forces for accurate mud displacement and removal. This study confirmed that high-resolution MWD survey data can provide additional precise input for casing standoff and mud removal simulation, resulting in a more realistic simulation result due to the appearance of microtortuosity and DLS. Simulation results using high-resolution directional survey data identified conditions where the original mud removal assessment using a standard survey was overestimated due to higher standoff. This result allows an appropriate level of risk assessment and cement job design optimization to improve both the casing standoff and mud removal, which will eventually impact the well integrity quality. This study proved that centralization and mud removal simulations can be, in some scenarios, optimistic if performed using standard trajectories. The results also proved that the risk assessments for the cement program designs will be evaluated differently because the enhanced simulations provide a more accurate result, which impacts the final centralization and mud removal to ensure effective zonal isolation.

Cement sheaths are among the most important barrier elements in petroleum wells. However, the cement may lose its integrity due to repeated pressure variations in the wellbore, such as during pressure tests and fluid injections. Typical cement sheaths failure mechanisms are formation of radial cracks and microannuli, and such potential leak paths may lead to loss of zonal isolation and pressure build-up in the annulus. To prevent such barrier failures, it is important to study and understand cement sheath failure mechanisms. This paper describes a series of experiments where we have used a tailor-built laboratory set-up to study cement sheath integrity during pressure cycling, where the set-up consists of down-scaled samples of rock, cement and casing. Cement integrity before and during casing pressurization is characterized by X-ray computed tomography (CT), which provides 3D visualization of radial cracks formed inside the cement and rock. We have studied how contextual well conditions, such as rock stiffness, casing stand-off and presence of mudfilm, influence cement sheath integrity. The results confirm that the rock stiffness and casing stand-off determine how much casing pressure the cement can withstand before radial cracks are formed in the cement sheath, where the rock stiffness is significantly more important than casing stand-off. Furthermore, it is seen that the radial cracks in the cement sheath continue into the rock as well. However, when a thin mudfilm is present at the rock surface, the cracks stop at the cement-rock interface, and the cement sheath withstands less pressure before failure. The bonding towards the rock is thus of importance.

Effective mud removal is a prerequisite to attain the cement coverage necessary for good zonal isolation. Because of this, the oilfield industry has dedicated considerable attention to the topic of mud displacement over the past 60 years. The first 2D annular displacement simulator was introduced in the 1990s and it is now widely available. The results are satisfactory for simpler configurations. However, for deeper wells with complex trajectories such as highly deviated or horizontal wells, the models start to show their limits. This paper discusses the advancements in mud displacement simulation that overcome the limitations of the previous generation simulator and provide a more realistic simulation in highly deviated and horizontal wells. A new generation simulator now provides high-fidelity results via a combination of: 1) a pipe displacement model, accounting for fluid contamination inside the pipe; 2) a high-resolution annular displacement model, accounting for the complex 3D annulus shape with full determination of axial and azimuthal flows; and 3) a stiff-string centralization model based on the finite-element method, predicting casing position in a 3D wellbore. A primary cementing operation for a horizontal well was studied and an unprecedented congruence was witnessed between predicted fluids annular concentration maps and ultrasonic cement log. The simulator was also able to predict complex channeling patterns in the annulus. These results allow a better understanding of the cement placement technique and provide means to optimize the sequence of fluids to achieve effective mud displacement in the well. Enabled by advancements in today’s computing capabilities, the new simulator is able to simulate both simple and highly complex scenarios more realistically. Finally, the new model allows better planning and decision making to achieve zonal isolation and well objectives.

Whether operators are drilling extended reach wells in prolific shale plays or offshore HPHT wells, well integrity remains the critical concern. Effective zonal isolation using cementing techniques is essential to mitigate risks and non-productive time associated with leaks, corrosion and contamination. Although well researched and considered a mature discipline, effecting cement placement in the annulus still has a significant degree of uncertainty. As global regulatory agencies respond to public concerns with drilling operations either in deepwater or unconventional plays, the industry is reviewing well construction best practices to reduce risk. The discipline of cementing has been given renewed focus. In spite of the industry's detailed understanding of the advantages of reciprocating and rotating casing during cementing operations it is applied to less than 10% on wells globally. This mechanical method, although proven to be the most cost effective remains the least applied. Why? A proven emerging technology, drilling with casing (DwC), developed the modern casing running tool (CRT). Using tools and drilling engineering methods developed from over 4,000,000 feet of drilling with casing; rotating casing to ream and while cementing is now a low risk activity. Employing the CRT on conventional casing running jobs delivers a measurably higher degree of probability that casing while reach bottom and effective zonal isolation by cement has been achieved. A new method of dynamic cementation, where pipe movement is maintained until cement begins to set maximizes the mud-cement displacement process. It can achieve a high quality completion using a combination of modern cementing software, real-time rig instrumentation and casing rotation/reciprocation with a CRT monitored to planned torque and weight levels while cement is pumped in the annulus. In this paper, barriers to change, a new methodology with its classification of dynamic cementation levels and field examples are presented. It investigates the positive effect of casing movement during cementing and reviewing cement bond logs.

Abstract In North-German gas fields, occasionally 5½-in. liners have to be run in 5?-in. boreholes. This low-clearance application does not represent the standard. This paper describes the steps taken to successfully run and cement these liners in spite of the extremely tight clearances by means of two case studies. One application is to run 5½-in., 32-lb/ft thick wall casing in 5?-in. holes to cover squeezing salt sections in order to provide long-term integrity of the well. The other application is to run regular wall 5½-in., 20-lb/ft casing to enable remedial sand control, which would not be possible with standard sized 5 or 4½-in. liners. In both applications, these liners had to be run through 5?-in. drift casing into a directionally drilled 5?-in. openhole with actual dogleg severities (DLS) of up to 9°/100 ft. Often, the drilled sections contain hard and abrasive sandstone layers, which have to be drilled with diamond impregnated bits. Thus, underreaming is not economically viable. To successfully run and cement the 5½-in. liners, the borehole has to be prepared properly by running extremely stiff reaming assemblies. The 5½-in. tubulars do have special flush connections (MUST or V&M-FJL). Experience has shown that a planned DLS of 6°/100ft is feasible. On regular wall 5½-in., centralization is achieved with Ceramic Carbon Fiber Stand-offs. The mud systems used ranged from low solid Formate mud (12.2 ppg with extremely low fluid loss and thin filter cake) to weighted water-based mud (16.4 ppg with high solid content). Additionally, to reduce friction, lubricants based on Glycol or Graphite were successfully applied. Finally, cement recipes have to be carefully adjusted to these mud systems. Introduction Some technically driven circumstances in drilling operations can lead to the necessity to deviate from proven standards. This paper focuses on how to successfully run 5½-in liners in 5?-in directionally drilled boreholes through prior set 7-in., 35 lb/ft liners. The gas produced by ExxonMobil Production Deutschland GmbH (EMPG, German ExxonMobil affiliate) is from fields in Northwest Germany (Fig. 1). In the fields east of a line from Bremen-Hanover, sweet gas is produced from the Rotliegend, the fields west of this line, produce both sweet and sour gas with a H2S content of up to 35% from the Bunter and the Stassfurt Carbonate respectively. German oil and gas producers agreed to a standard casing scheme: 18"-in. surface casing in 23-in. borehole, 13?-in. intermediate casing in 16- or 17½-in. borehole, 9"-in. production casing in 12¼-in. borehole, 7-in. production liner or casing in 8?-in. borehole and 5-in., respectively 4½-in. production liner in 5?-in. borehole (Fig. 2). The borehole diameter of 5?-in. is driven by the drift diameter of the prior set 7-in., 35 lbs/ft casing or 7"-in., 59 lbs/ft thick wall casing. Differing from this standard, occasionally 5½-in. liners have to be run in 5?-in. boreholes. The two applications appearing are either running 5½-in. thick wall casing to cover squeezing salt sections or regular 5½-in. casing to enable remedial sand control in the reservoir. This paper describes the steps taken to successfully run and cement these liners in spite of the extremely tight clearances by means of two case studies. The Two Applications for Tight Clearance Operations Case 1 One application is to run 5½-in., 32 lbs/ft thick wall casings in 5?-in. holes to cover squeezing salt sections in order to provide long-term integrity of the well.

Abstract For effective zonal isolation, drill cuttings and gelled, dehydrated drilling fluid (GDDF) should be removed from the wellbore before a cement job, but such removal can be a challenge when the wellbore is deviated and the casing is not centered. This paper discusses simulated wellbore experiments that investigated the effect of different factors on the removal of drill cuttings and GDDF from a horizontal well bore. The parameters studied included eccentricity, flow rate, hole size, casing size, fluids pumped as flush/spacer, and pipe movement. The results showed that below a certain flow rate, the drill cuttings and GDDF could not be dislodged from the wellbore. In field applications, this flow rate must be known so that job designers can selectively design flushes that will effectively dislodge the drill cuttings and GDDF. As expected, eccentricity also alters the velocity profile in the narrow side of the annulus, and geometry was also a factor in removal efficiency. The experimental setup, procedure, and results are discussed in detail. Flow rates needed to dislodge the drill cuttings and GDDF are also discussed, A numerical analysis of the fluid flow in wide and narrow annuli was also performed. Introduction Cement operators should always use the following guidelines to obtain a successful cementing job. Remove the drill cuttings. Remove the gelled and partially dehydrated drilling fluid. In some cases. this fluid will have the consistency of a paste. Hereafter, it will be referred to as partially dehydrated paste (PDP). Design the cement slurry to meet properties such as pumping time, fluid loss, gas migration, etc. In addition, design the density, rheology, and other placement parameters so that the cement slurry will displace the fluid ahead of it and seal the entire annulus. The cement formulation should also provide zonal isolation over the life of the well. The removal of drill cuttings and PDP are influenced by the following: – properties of drilling fluid, fluid loss, plastic viscosity etc, a temperature, pressure, differential pressure across the formation – shutdown period – drilling fluid formulation – wellbore details – casing/drillpipe size – hole size – standoff/eccentricity – pore pressure – fracture gradient For successful PDP removal, the downhole forces in both the narrow and wide sides of the annulus must exceed the yield stress of the PDP under downhole conditions. The force exerted could depend on the following factors: – flow rate of fluid – standoff/eccentricity – properties of fluid – pipe movement – wellbore geometry – scratchers Although the general effect of these parameters on a cement job is well known, the designer must quantify the effect of each factor to optimize the design of each individual well. For a wellbore with a certain drilling fluid, geometry and standoff, it may be difficult to generate needed forces by hydraulic means only. In such cases, ways to reduce the downhole forces should be explored. P. 347

SPE Members Abstract Centralizer/hole size combinations, minimum centralizer restoring forces and recommended test procedures are specified in API specification 10 D. This specification also includes a recommended procedure for calculating the lateral forces exerted by casing on centralizers in 2-D inclined borehole. However these recommendations are no longer adequate for highly deviated, horizontal boreholes and deep heavy strings. Extensions are needed in order to consider 3-D borehole curvature variations due to simultaneous changes in hole inclination and direction and to guarantee the influence of external loads on the casing strings. A computer program, named "Lateral Load Program (LLP)", was developed and field tested during the last few years based on the above assumptions. The LLP has the capability to calculate, starting from wellbore profile data (measured depth, inclination and direction), the dogleg severity, the spacing (constant or variable), the axial and lateral loads. The program also computes the stand-off according to the sag deflection prediction, based on lateral load and tension force from the pipe prediction, based on lateral load and tension force from the pipe hanging below the centralizer, and generates a casing stand-off/depth/deviation and the hookload diagrams in advance, representing a valid support for operational planning and follow-up. Actual field data studies show that the LLP is accurate in predicting the real hookload; in the cased hole such predictions predicting the real hookload; in the cased hole such predictions are exact, whereas in open hole they are few tons of the actual up and down weight. As a result of our field experience in many years of drilling activity, it is possible to conclude that achieving a stand-off of 60–70% is not enough to avoid channelling and to obtain proper cement placement. Based on this experience, by late 80's the casing centralizers spacing in deep, deviated and horizontal wells was optimized in order to achieve, as close as possible, a 100% stand-off. Several field examples confirm this possible, a 100% stand-off. Several field examples confirm this assumption. The LLP is still upgrading and the fixed ends boundary condition is used in the last version ('91) for the calculation of casing deflection between two centralizers. Introduction The purpose of every casing operation is a successful primary cementing job that will ensure the performance of a producing well. In a high quality cement job, mud and gas channels are permanently eliminated by completing a positive hydraulic permanently eliminated by completing a positive hydraulic seal between the casing and the formation. Many elements effect the success of cementation including casing centralization, pipe movement, fluid displacement rate, fluid volume/contact time, bottom hole temperature and elapsed time between circulations. The most important factor, however, is thorough job planning. A team effort of technicians and engineers from the planning. A team effort of technicians and engineers from the Operating Company, the Service Companies and the Drilling Contractor will help to ensure that every element is carefully considered so that each phase of the cementing job Is optimized. Uniform centering of the casing in the borehole Is critical. Regardless of the flow patterns and techniques selected, if the casing is against the wellbore wall, the cement will never completely surround the casing. Therefore, channeling cannot be eliminated. The majority of the work currently available for calculating displacement efficiency is based on centered pipe with a fairly uniform annulus completely around the casing. However, due to the natural curvature induced into the wellbore during drilling, only few percent of holes drilled are actually round. Some of them are percent of holes drilled are actually round. Some of them are eccentric with some washout and irregularities on one side or the other. The lack of proper slurry placement velocities dictate the need of pipe movement to force cement into these irregularities. Properly centered casing and pipe movement are closely related factors in primary cementation. Pipe movement is used to enhance displacement efficiency and to reduce channelling of nonuniform fluids. This can only be achieved through proper pipe centralization which eliminates drag caused by differential pipe centralization which eliminates drag caused by differential or wall cake sticking. In the formula defining differential sticking, the only variable that we can directly modify is the amount of surface area that the casing has in contact with the wellbore wall. P. 713

Abstract When designing a primary cement job, more emphasis is usually placed on optimizing the cement slurry properties than on its placement in the wellbore. This lack of balance can be easily explained. On one hand, a wide range of additives is now available to control the major cement properties required in a given situation. On the other hand, placement techniques very often still rely on rules of thumb which are not always supported by experience. Recent technological advances should restore the emphasis to cement placement and mud removal. Field engineers can now take into account, quantitatively, most of the key parameters in cement placement and optimize parameters in cement placement and optimize the process. This paper describes the application of this new technology to a comprehensive cementing design for production casing. This design was developed for a platform in the Green Canyon area of the Gulf of Mexico. In the first part of the paper, the cementing problems encountered before the plan's implementation are discussed. These included (1) poor zonal isolation which necessitated remedial cement squeezes; and (2) gas migration which resulted in casing pressure between the surface and production casings. In the second part, the authors present the step-by-step methodology which was used to optimize the mud removal process. A computer simulation was used to determine the centralizer placement, fluid properties, and pumping conditions required to provide stable pumping conditions required to provide stable interfaces between the different fluids during the cementing process. The stable interfaces prevented mud pockets or channels from being prevented mud pockets or channels from being left in the cement after it was in place. Since the new laminar flow design procedure has been implemented, no remedial squeezes have been required on 11 successive cement jobs. This is especially noteworthy since the average angle of these wells was approximately 50 deg. In addition, potential gas migration problems have been prevented. Introduction It is nearly possible to provide a cement slurry with all the optimum properties for a particular application. However, primary cementing failures still occur in the field. The problem is that the best, most expensive cement system in the world is totally useless if not placed properly in the wellbore. For the cement job to properly in the wellbore. For the cement job to be successful, the cement must displace the mud out of the annulus 360 deg. around the casing across the intervals where isolation is required. P. 733

Abstract An ultrasonic tool has been developed for MWD applications that simultaneously performs real-time bore-hole caliper measurements and real-time gas influx detection The caliper determines the ovalness of the hole with a high degree of accuracy and excellent vertical resolution. These measurements are transmitted to the surface and also used to compensate LWD measurements. Furthermore, with early and accurate real-time caliper measurements, bore-hole instability can be detected. Real-time gas influx detection insures early and reliable gas kick detection and should provide a considerable improvement in drilling rig safety. The new tool is particularly useful for avoiding problems associated with shallow gas formation problems associated with shallow gas formation where response time for kick detection is critical. Introduction During drilling local changes in bore-hole shape or diameter are common, especially in a highly deviated hole. Without proper reaming, the drill string can become stuck resulting in added expense and the loss of valuable rig time. When monitoring the hole size during drilling, key-seats and other geometrical discontinuities are easily detected. So, correct and timely decisions about hole reaming can be made, reducing the occurrence of stuck pipe. Another advantage of the real-time caliper is the early detection of bore-hole instability. This caliper helps the driller make the proper decision such as either reaming the critical zone, changing the flow rate to reduce hole erosion, or modifying the string RPM to reduce shocks with the formation. Thick mud cake can build up with time in front of permeable formations, adversely effecting most permeable formations, adversely effecting most logging measurements. Furthermore, its removal might be necessary to insure the proper formation seal with the cement. Comparisons between caliper logs obtained in real-time and while tripping indicate the location of mud cake buildup. Such detection is critical as this thick cake may appear in front of pay zones. Anyway, a real-time caliper log becomes a necessary quality control enhancement now that logging while drilling has become common practice. practice. The other purpose of the new tool is the down-hole detection of gas influx in the well-bore. Ultrasonic measurement allows accurate and reliable gas detection in the bore-hole because the acoustic properties of drilling mud change P. 439

Abstract Logging while Drilling (LWD)* tools are formation evaluation sensors engineered into drill collars. Using LWD in horizontal wells offers significant advantages over other logging systems for formation evaluation. When LWD is provided in real-time via mud pulse telemetry the system becomes a geological steering tool which can be used to accurately place the horizontal section with reference to formation features and/or fluid contact. The combined benefits of formation evaluation and real-time geological steering make LWD an essential tool for many horizontal wells. We will describe the benefits of LWD measurements and the improvements in both drilling and logging efficiency which LWD offers. These features are illustrated with practical examples of LWD from a number of horizontal practical examples of LWD from a number of horizontal wells in the North Sea. Although these examples are from horizontal wells in particular, the same benefits can be realized in directional wells in general. Introduction Success in the drilling of any development well can be judged using several criteria, the foremost being the safety and efficiency of the drilling operation. While intersection of the desired target pay zone is an obvious requirements in all wells, the correct placement of the wellbore within the pay zone has a crucial role in determining the subsequent pay zone has a crucial role in determining the subsequent commercial success of a horizontal well. The technique of horizontal well drilling owes its current success, in part, due to developments in drilling technology, particularly steerable downhole motors and PDC bits. With these improved drilling techniques, the PDC bits. With these improved drilling techniques, the direction of a wellbore can be accurately adjusted, but the control of any such adjustments relies on the provision of accurate downhole measurements of well position while drilling. Both geometrical measurements (depth, inclination and azimuth) and formation measurements may be required. Measurement While Drilling (MWD) traditionally fulfils the role of providing well direction and inclination measurements in real-time. Real-time correlation and reconnaissance may also be provided with gamma-ray and resistivity sensors. Just as drilling technology has improved, so logging technology has evolved with the introduction of LWD tools to complement the conventional MWD. LWD provides accurate, quantitative measurements of resistivity, provides accurate, quantitative measurements of resistivity, natural spectral gamma-ray, neutron porosity, and formation density; all of which are available in real-time when combined with MWD. Utilization of the combined LWD/MWD system during the drilling of a horizontal well offers to the user real-time geological steering capabilities as well as the primary formation evaluation measurements.

SPE Members Abstract In recent years emphasis has been placed on the use of "turbulent flow" spacers. Normally this practice helps in obtaining higher drilling fluid practice helps in obtaining higher drilling fluid displacement efficiencies, and thus a good cement job. However, depending on placement rates, well geometry, etc., the solids required in these relatively thin spacer fluids can settle even in dynamic conditions. This problem is manifested in deviated wells by a channel of solids forming on the low side of the pipe and annulus. This channel of solids prevents placement of a continuous cement sheath in the annulus, providing a potential path for interzonal communication. To develop a better understanding of this phenomenon, a full scale laboratory investigation phenomenon, a full scale laboratory investigation was conducted using field mixing equipment and a large scale, simulated wellbore test facility. Factors evaluated for their influence on spacer settling included (1) various pipe geometries, (2) pipe centralization, (3) fluid rheological pipe centralization, (3) fluid rheological properties and composition, (4) flow rates, and (5) properties and composition, (4) flow rates, and (5) well deviation angles. As a result of this investigation a mathematical correlation was developed to predict minimum flow rates required to alleviate spacer solids settling in highly deviated wells. It is apparent from these test results, that achieving turbulent flow is not the sole criterion for obtaining optimum spacer efficiency. This paper presents test procedures, equipment descriptions, presents test procedures, equipment descriptions, and discussion of results, in addition to a full definition of the problem of spacer settling. Introduction The recent emphasis on horizontal drilling in the oil industry has led to an increased awareness of problems unique to conditions which could be encountered only in highly deviated or horizontal wellbores. One such concern has developed over the use of "turbulent flow" spacers to improve drilling fluid displacement and thus obtain a better cement job. Since turbulent flow spacers are those which can be pumped in turbulence at relatively low rates, they must, of necessity, be low viscosity fluids. To obtain necessary fluid densities, solids such as barite, hematite, and sand can be added to spacers as weighting materials. Suspension of solids in turbulent flow spacers has not been considered to be a problem under dynamic conditions in vertical or slightly deviated wellbores. In highly deviated wellbores, however. suspension becomes a major consideration since these solids can settle from the fluid during pumping operations. Identification of this pumping operations. Identification of this potential problem stemmed from previous studies potential problem stemmed from previous studies conducted on a large scale displacement model. These studies concluded that certain fluid properties must be maintained within a range of properties must be maintained within a range of values that prohibits settling of solids from the fluid. Failure to maintain solids suspension results in deposition of solids along the low side of the annulus. In an effort to define the conditions under which settling occurs and to investigate the degree of settling, a major project was undertaken. Findings from this study led to the development of guidelines to help prevent solids settling in turbulent flow spacers. These studies were conducted in a laboratory-type environment using test facilities designed to duplicate field conditions to the fullest extent possible. P. 223

SPE Member Abstract Economic considerations have required many contractors and rental companies to repair and reuse downhole equipment that would have been discarded much sooner in previous years. While the practice of striving to obtain the maximum life cycle for each piece of equipment should be encouraged, increased attention must be given to inspection and repair methods. API Specifications detail mechanical properties and dimensions for the manufacture of new products. But the vast scope of repair of used equipment cannot always be covered by exacting procedures or specifications. Consequently, the repair and maintenance of used equipment is often left to the imagination and ingenuity of the user and/or the repair shop foreman. Successful repair may require the interpretation and blending of several specifications by competent machine shop personnel. One of the objectives of this paper will be to review repair methods that are being used to increase the life of downhole tools. Particular attention will be paid to welding procedures. Introduction Recent articles have focused attention on the aging condition of the drill stem. Highlighted in these articles is the diminishing supply of quality drill pipe. One article estimates that 200 million dollars must be spent in the next two years to replace worn drill pipe in order to maintain a fleet of 750 active rig's. In these discussions, little has been said about the condition of the other components of the drill stem. Be assured that the drill collars, reamers and stabilizers, whether belong to the contractor or to a rental company, are also maturing. Cannibalism has left a carcass of bare bones not only on rigs but also in the yards of rental companies and suppliers. In efforts to reduce cost, rental companies and manufacturing companies have not replaced raw material as it has been used. Stung by being trapped with excess inventories in the downturn of 1981, many suppliers have adopted a policy of not purchasing raw materials until a firm order is in hand. This situation is workable only as long as material can be found in someone's excess inventories. But a drying-up of readily available material is now becoming apparent. Orders for the most popular sizes of alloy bars must now be placed directly to the steel mills. The mills also are showing a reluctance to inventory steel bars. Delivery times from the mill are being quoted at 16 to 20 weeks and some mills are requiring order quantities of full mill heats. In the near future we can expect to see extended deliveries and reduced size selections as inventories continue to be depleted. In some cases, the effect of the material shortages can be softened by repairing equipment that might in better days wind up in the scrap yard. This paper will focus on several of the most common repair procedures that can be used to extend the life of downhole tools. Inspect Before Repairing An assessment of the condition of the equipment must be made before repairs can be made. In the case of fatigue cracks, magnetic particle inspection is the most common method used to locate defects. Visual inspection is used to ascertain the seriousness of almost all other types of damage and this is where problems arise. Often this is a judgment decision. Many of the major oil companies have begun to rely heavily on third party inspection companies for advice. This can create some problems if these inspectors work only from standards that were developed for new equipment. Often decisions are influenced by aesthetics rather than useability. API Standards and Repairs Few people realize that API Standards apply only to the manufacture of new products. Other than the dimensions and gaging practices used on rotary shoulder connections, most API Standards are hard to adapt to used equipment. In the absence of a uniform repair criteria to apply to used equipment, the imagination and expertise of the shop foreman and machinist are often the deciding factors as to how and what repairs are made. P. 685^

SPE Members Abstract This paper describes and quantifies the importance of some geometrical parameters on the main output of the cement bond log, i.e. the attenuation of a sonic wave propagating along a casing to cement interface. These geometrical parameters are the cement thickness, the casing stand-off, the percentage of cemented area and the shape of the noncemented channels. Also the nature of the fluid in the noncemented channel has been investigated. These experiments were performed with a laboratory cement bond tool of variable spacing with between 0.5 and 3.0 feet, coupled to an oscilloscope and a data acquisition unit. It is observed that cement sheath thickness is an important parameter than can significantly affect the output of the tool up to a thickness of more than 2 inches. As a first approximation, the percentage of cemented area is confirmed to be in linear relationship with the attenuation rate. Casing stand-off can also change the log output by a factor of up to 30%. Conversely the shape of the channel is found to have no significant influence on the result provided the percentage of cemented area is the same. The nature, from gas to liquids, density and gel strength been found to be negligible factors. Some of the conclusions are illustrated through the interpretation of several field logs of cased hole or of open hole sections where both the cement and the caliper logs were available. Introduction Since the introduction of the Cement Bond Log (CBL) in the late 50's little experimental work has been performed in order to explain the output of the log in relation with the downhole annular configuration. The effect of vertical channels was studied and a linear relationship was observed between the attenuation rate and the percentage of circumference bonded for a centralized pipe. Later experimental and theoretical studies quantified the influence on the CBL amplitude of casing diameter, casing thickness, transmitter to receiver spacing and cement compressive strength leading to the construction of a nomograph well known as CBL interpretation chart. This last chart which has been modified to take foamed-cements into account suffers from some limitations with regards to tool and casing centralization, cement thickness, well history, etc… Later on, it was also found that the bond log amplitude was greatly influenced by the acoustic properties of the fluid in the casing and by downhole conditions affecting the transducer response, leading to the elaboration of a borehole-compensated cement bond tool. However not all the parameters have been considered and some field logs still cannot be explained with existing CBL interpretation techniques, resulting in totally unsuccessful squeeze cement jobs in wells showing poor bond logs. In the present study, we investigate the influence of critical borehole geometrical parameters which were not considered, or not completely covered in the past. These include casing stand-off, cement thickness, percentage of bonded area, shape of the channel and nature of fluid. P. 763^