Test Results of a Corrosion Logging Technique Using Electromagnetic Thickness and Pipe Analysis Logging Tools

Wellbore irregularities can cause excessive mechanical friction forces while attempting to land casing strings, and unfavorable conditions for primary cementing of casing strings. In an eccentric annulus, the fluid velocity is largest in the wide section of the annulus. The drilling fluid on the narrow side of the annulus may be immobilized due to the lower wall shear stress in this section of the annulus. A direct consequence for the primary cementing operation is the potential for having residual drilling fluid between casing and formation, and thereby failing to achieve zonal isolation and adequate mechanical support for the casing. Casing strings are usually fitted with centralizers at predetermined intervals in order to achieve a minimum degree of centralization in the wellbore and efficient fluid displacement during primary cementing. Centralizer distribution and design are based on assumptions of regular wellbore geometries and often analytical models for estimating lateral casing string displacement in the well. The latter assumption implies that bending moments are not transmitted across centralizers, and may lead to nonconservative centralizer designs. To investigate the effect of irregularity and casing string stiffness, we consider a stiff string model that approximates the casing string as finite beam elements with bending and axial degrees of freedom at each end, thereby accounting for transmission of both axial and bending stresses between elements. In this work, we evaluate wellbore irregularity by inspecting a six-arm caliper log and estimate the cross-sectional shape of the wellbore by cubic spline interpolation between the arms of the caliper tool. Analyses of the caliper logs indicate that long, continuous strecthes conform to the nominal wellbore size, and that local hole enlargements may be significant. Irregularities are found to be largely symmetric about the wellbore axis, although some examples exhibit elliptic or oval shapes that may conform with local in-situ stress directions. We detail the stiff string model assumptions and implementation for evaluating casing centralization, and demonstrate the approach on model irregularities and on selected caliper log sections. Calculations suggest that bow spring centralizers result in better casing centralization in vertical parts of the wellbore, while large bow spring compression favour rigid centralizers in more inclined parts of the well. Axial compression close to the bottom of the wellbore section leads to a geometric softening effect of the casing, which affects transverse displacement and centralization between centralizers. Higher in the well where the casing is in tension, a geometric stiffening effect reduces transverse displacement. In proximity of washed out and irregular sections, centralization is affected both by placement of the centralizers and a reduction in the restoring capability of bow spring centralizers.

Riserless drilling poses numerous operational challenges that adversely affect the efficiency of the drilling process. These problems include increased torque and drag, buckling, increased vibration, poor hole cleaning, tubular failures, poor cement jobs, and associated problems during tripping operations. Riserless drilling in deep and ultra-deep water, as well as drilling to deeper depths, requires improved models and comprehensive analyses, especially when larger-diameter casings are run and cemented in a deviated or directionally drilled tophole environment. Current methods that lack proper modeling will severely overestimate hookload values when casing strings are run in and underestimate in the pick-up load estimates. A new modeling approach is proposed to calculate appropriate hookload values, as well as torque and drag. This method can model situations in which the drillstring/casing string is in open water or in openhole under various operating conditions. Both soft- and stiff-string models are used in the hookload estimates and in the wellhead side-loading calculations. Hookload calculations and buckling limitations for the scenarios in which casing and inner strings are run with drilling mud inside the inner string, seawater in the outer string, and pad mud in the hole below the mudline, are presented. The study indicates that the results are influenced by various parameters, including depth of the mud line, offset of the wellhead from the rig center, wellbore inclination, curvature, wellbore torsion, and angle of entry into the wellhead, as well as by the complexity arising from wind, wave forces, and ocean currents. This study compares simulated predictions with actual well data from wells from Angola and the North Sea and describes the accuracy and applicability of the model. It also presents several examples of surface casing-string failure.

After implementing a water injection project with high temperature (up to 235°F @ surface) sourced water in existing wells, 63% of the conventional Wellhead associated with waterflooding installed showed growth/inclination at the surface. A detailed analysis of twenty-seven wells in the Orient Basin of Ecuador was performed, where onsite measurements and engineering calculations of the loads and elongations of the production casing and tubing strings were caused by thermal effects. A specialized tubular modeling software was used to simulate the water producer wells and injector well thermal profiles, casing elongation, and buckling. The produced water has temperatures superior to 200°F and is transferred directly to the injector wells without any allowed time to cool down. The analysis focused mainly on the 9-5/8″ production casing since it is not cemented to the surface and has almost 6,000ft of free pipe able to elongate due to high-temperature injected water. As the other casing strings were cemented to the surface, it was assumed that they were adequately anchored, and no elongation would occur. All the wells were inspected before entering service, and no wellhead deformation was observed. Once operations started, the surface temperatures reached up to 235°F on the water producers and injectors. After six months, the production operators noticed the first signs of wellhead movement, with consequent inclination. A survey was carried out in 27 wells, where the wellhead deformations were measured by taking the projection in 3 planes (X, Y, and Z). Out of 27 wells surveyed, two water producers presented an inclination above 2° and one injector well above 1.5°, which was deemed excessive. It was possible to establish a good correlation between the specialized tubular modeling software results and the deformations measured at the surface, enabling the development of guidelines to define if high-temperature wellheads with expansion capabilities would be required. It also evaluated the possibility of using insulated packer fluids to minimize heat transfer and production casing elongation. The simulation estimated an average elongation reduction of 28% and 41% when water-based and oil-based packer fluids are used, respectively. This work created a workflow to identify wells with a high risk of suffering wellhead deformation caused by high surface temperature. Combining the simulation results with the field measurements made it possible to determine when deformation at the surface was expected and high-temperature wellheads with expansion capabilities were needed. It also evaluated the effectiveness of insulated packer fluids in reducing the casing elongation and avoiding the installation of such wellheads.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180065, “Thermal Effects on Subsea Wellhead Fatigue During Workover Operations,” by L. Cantinelli Sevillano, J. De Andrade, S. Sangesland, and M. Stanko, Norwegian University of Science and Technology, prepared for the 2016 SPE Bergen One Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed. Intervention and workover operations can significantly affect the structural integrity of subsea-wellhead systems with regard to their fatigue life. The increasing frequency of these operations has called for a renewed focus on the fatigue capacity of subsea wells, which has greatly improved the overall methodology used for wellhead-fatigue analysis. However, thermal effects along the well have yet to be incorporated. This paper analyzes wellhead-fatigue damage during a workover operation considering the thermal effects. Methodology The goal of the present study is to investigate the effects of the temperature variation along the well on wellhead-fatigue- damage rates by incorporating the temperature profiles of casing strings and cement into the fatigue-damage assessment of a particular wellhead system during a workover operation. In this study, a decoupled approach is proposed. The temperatures of riser, wellhead, and well components are calculated for different instants during the workover operation using a finite-difference method. Then, the temperature profiles for a given moment during the operation are incorporated into a 3D finite-element model (FEM) of the wellhead system. A structural analysis with focus on stresses at the fatigue hot spots is performed. Subsequently, a dynamic analysis of the riser provides the loading time history to which the wellhead is subjected; finally, combining the results of the structural analysis and the riser-response analysis enables the fatigue damage during the simulated operation to be estimated. The well adopted in this study follows a conventional subsea-completion program on the Norwegian continental shelf, with four casing strings and a production liner. Temperature Calculations. It is assumed that enough time has passed—between the shutting down of production and the moment that the workover riser is connected to the wellhead and the workover operation begins—for the temperature in the well to reach the undisturbed geothermal temperature profile. The workover operation simulated for temperature calculations consisted of injecting and circulating a heavy fluid until the hydrocarbons in the well were displaced. After that, circulation was stopped. The temperature profiles were calculated with a finite-difference method. During the simulated cold-fluid injection into the well, the deepest sections of the well are subjected to the largest temperature drop, given that the fluid is at lower temperature than the surrounding formation and well fluid, while the uppermost sections experience the effects of a circulating fluid at a higher temperature. Circulation was deemed to last approximately 3 hours.

Sidetracking a cased wellbore presents numerous challenges because the operators have to plan ahead to select the sidetracking depth and then ensure that all the objectives are met from a well authority for expenditure and geological target perspective. The quality of the geological target window is of great concern to operators because it ensures that the subsequent bottomhole assembly (BHA) will pass through the window without any problems. Sidetracking the wellbore when the milling assembly has to cut two strings of casing is an additional unique challenge. The centralizer and casing collar locator along the length of the wellbore at and in the region of the kickoff point are significant because they can be additional risks, which can lead to costly multiple trips to ensure that the window is in good-quality form. An operator was faced with potential geological losses at the kickoff point in a wellbore while attempting to sidetrack an existing wellbore containing 9.625-in., 43.5-lbm/ft L80 buttress thread casing, and 13.375-in., 68-lbm/ft K55 buttress thread casing, dual strings at the kickoff point. The BHA for this challenging application was modeled using a finite-element analysis (FEA)-based modeling system to select the optimum BHA to sidetrack the wellbore with the least amount of vibrations. The feasibility of using a bi-mill vs. tri-mill BHA was evaluated. As a result, a parameter road map, taking into consideration the dimensions of the whipstock slide and mill position during the milling operations, was finalized. The placement of the centralizers and casing collars along the length of the casing at the kickoff point was considered. The exact locations where the lead mill would initiate the cut at each casing string were analyzed to determine the whipstock setting depths. A corrosion and collar locator tool was used to identify the collar location along the 13.375-in. casing because standard casing collar locator logging tools were not be able to identify the location of the casing collars along the length of the 13.375-in. casing string. Whipstock simulation software was used to check the bending moments and stresses for the pass-through BHA because the dogleg through the window can create additional issues and challenges. The program calculates the dogleg severity for a liner or BHA pass-through in addition to forces and stresses on the liner or BHA. The total quantity of cuttings that would be generated from the milling operation while cutting two strings of casing was also analyzed. This methodical planning resulted in a successful dual-casing exit operation. The success is the result of a proactive planned initiative to mitigate BHA shock loading, which included real-time monitoring using a predictive compressive-strength analysis system. The proactive plan also increased confidence in the FEA-based modeling system's ability to accurately identify the root cause of damaging vibrations while sidetracking through carbonates in a dual-casing Kuwait well.

In the hot dry rock (HDR) concept of extracting geothermal energy, as developed by the Los Alamos Scientific Laboratory (LASL), a manmade geothermal reservoir is created by drilling a deep hole into relatively impermeable hot rocks, creating a large surface area for heat transfer by hydraulic fracturing, then drilling a second hole to intersect the fracture to complete the closed circulation loop. The completion of HDR geothermal wells presents cementing problems that are unique. Current presents cementing problems that are unique. Current well depths are from 10,000 to 14,500 ft (3 to 4.4 km) with bottom hole temperatures up to 525 degrees F (275 degrees C). During investigation and development of the reservoir, water injection flows may lower the temperature of the entire wellbore to 104 degrees F (40 degrees C). As a result, the casing string may be subjected to temperature stress cycles representing differential temperatures of up to 455 degrees F (235 degrees C). Experience has shown that the conventional high-temperature completion cement formulation of Class A or B portland cement, stabilized with 40% silica sand, does not withstand these cyclic stresses, and that rapid deterioration of casing-to-cement and cement-to-formation bonds occurs, which allows significant flow in the resulting microannulus. Investigations and tests (both laboratory and downhole) are being conducted by LASL, and other national and private laboratories, to determine other portland cement formulations, thermal setting cements, and special packer completion techniques which will better withstand the temperature, pressure, and flow requirements of HDR geothermal systems. This paper will describe (a) the performance history of casing cement for the existing EE-1 injection well, (b) the proposed cementing plan for the EE-2 injection well presently being drilled, and (c) the completion system being tested in EE-1 for expanded use in EE-2. Introduction The Los Alamos Scientific Laboratory (LASL) for the past six years has been actively investigating the potential for and problems associated with extracting geothermal energy from hot, but essentially dry, rock at moderate depths. In the Los Alamos concept, a manmade geothermal reservoir is formed by drilling into a region of suitably hot rock and then creating a large fracture, using conventional hydraulic fracturing techniques developed by the oil industry. After forming a circulation loop by drilling a second hole into the top of the fractured region, the heat contained in this reservoir is transported to the surface by circulation of water. The water in the earth loop is maintained as a liquid by pressurization at the surface, increasing both the rate of heat removal from the fractured reservoir and the amount of heat transported up the withdrawal hole. To test this concept, a deep exploratory hole (GT-2) was completed in 1974 to a depth of 9610 ft (2929 m) in the granitic basement rocks of the Jemez Mountains of northern New Mexico at Fenton Hill (Fig. 1). The bottomhole temperature was 388 degrees F (197 degrees C). A near-vertical hydraulic fracture with a radius of about 400 ft (120 m) was created near the bottom of GT-2. Drilling of the second deep hole, Energy Extraction Well No. 1 (or EE-1), to intersect the fracture began in May 1975, about 250 ft (75 m) north of GT-2. It was completed in October at a depth of 10,053 ft (3064 m) and a bottomhole temperature of 400 degrees F (205 degrees C). Below 6240 ft (1957 m), EE-1 was directionally drilled to turn the hole through a 205 degrees spiral to create the underground connection. EE-1 was cased to a depth of 9600 ft (2926 m) with 7-5/8-in. casing and forms the injection well of the underground loop.

The optimum utilization of underground space for the emplacement and storage of waste and surface water can be achieved through an understanding of the geohydrologic environment. The emplacement of liquid waste and the artificial recharge of aquifers generally requires the drilling of exploration, injection, and monitoring wells. Some geophysical logs are run on almost all wells drilled for deep disposal. Even more information could be obtained, however, by utilization of all available logging techniques. To date, geophysical well logging has not been applied widely to artificial recharge projects; however, borehole geophysics is being used by the U.S. Geological Survey to study geohydrologic parameters related to recharging the Ogallala Formation on the High Plains of Te as. Geophysical well logs provide preinjection data necessary for the selection of environments for liquid waste or water storage. Logs provide data on the location, thickness, and lateral continuity of storage zones and confining beds, percent and distribution of total or effective porosity, and the relative magnitude of permeability. Intergranular and fracture porosity can be discriminated by crossplotting acoustic velocity and neutron or gamma-gamma logs. The distribution and orientation of preinjection fractures can be determined by acoustic televiewer logs. Logs provide data on the chemical quality of the native fluids and the mineralogy of the aquifer, which are necessary to predict chemical reactions with injected fluids. The temperature and conductivity of the interstitial fluids ay be measured directly and their specific gravity and viscosity may be calculated from log data. Because aquifers overlying injection zones can be polluted by improper well construction or well failure, geophysical well logs should be used to guide the design, construction, and maintenance of injection and monitoring wells. It is important to answer questions such as: are the casing strings and screens properly installed; are they plugged or corroded; does the grout fill the annular space and is it properly bonded to the casing; and, are there leaks through the casing, between pipe strings, or through the annulus? After waste injection or artificial recharge has started, logs provide in-situ measurements of changes in the system. We have found that an increase or decrease in porosity caused by solution or precipitation in pore spaces or cavities may be detected. This type of information not only explains changes in well efficiency End_Page 1597------------------------------ but provides the basis for selecting remedial treatment. Accidental hydraulic fracturing caused by drilling or injection can be the reason for vertical leakage through confining beds, and acoustic televiewer logs can locate these fractures. The distribution and velocity of injected water and the location of chemical or thermal pollution may be determined by means of temperature logs. We have used temperature logs to map the horizontal and vertical distribution of injected fluids. Diurnal thermal changes in injected water provide the basis for measuring the velocity of flow and its change with time. End_of_Article - Last_Page 1598------------

Introduction The need for a simple and economical way of determining the operating efficiency of input wells has been evident for many years. Considerable time and money is spent each year in the maintenance of injection wells. Often the results obtained by work-over operations and various treatments do not pay back the extra cost. A method is needed to determine which wells can be expected to respond favorably to treatment. The application of build-up analysis to input wells, both water and gas, is helping greatly ill solving the problem. The purpose of this paper is to show how the conventional build-up equations can be applied to fluid input wells, how the results are used to evaluate the wells' input efficiency, and to give examples of field tests. Build-Up Equation The use of pressure build-up curves in evaluating producing wells has been a valuable tool in the oil industry, particularly in the last few years. The mathematical analysis of these pressure vs time curves has been treated by several authors, some of whom are listed in the references. More recently it has been confirmed that these same equations are applicable to water injection wells and also to gas injection wells, with some restrictions. The equations used for this study are given in Fig. 1. Application To Input Wells The application of these build-up analysis equations to input wells can disclose many useful things about the well and the formation. These include the relative amount of damage or improvement existing in the formation immediately at the wellbore. A comparison of these tests before and after workovers will indicate the degree of success accomplished by the well treatment. These analysis also furnish a yardstick to measure the effectiveness of different well completion methods. They provide a guide to use in a selective plugging program as well as determining the extent of formation fractures. When the effective permeability is considered in conjunction with the skin effect, the injection rate, and the injection pressure, a better understanding of the well's performance is usually reached. One requirement for the use of these equations is that enough of the injected fluid must be in the formation to insure that the measured pressure drop occurs in that phase only. Minor adjustments may be necessary in some gas input wells for the compressibility factor as well as the weight of the gas column.

On the suitability of premium OCTG tubing connections for CCS CO2 injection wells – a full scale physical evaluation

By using down-hole ejection of radioactive fluid and two gamma counters the velocity of flow at a given point or the determination of whether or not fluid has passed a given point can be determined accurately on production or injection wells. In this method the counters are positioned at the proper points, a small concentrated quantity of radioactive fluid is ejected, and a recorder operating in time-drive records the time interval or fluid movement past the counters, each counter recording on a separate pen for a permanent record. Inside the casing or in open hole if a caliper log is available, a time profile and resulting velocity profile determines the full injection or production distribution. During injection profiling the procedures readily point out and locate any channeling which may exist. Equally simple job procedures are available for detecting casing leaks, tubing leaks, leaking packers and many other operational problems which are detectable by a study of fluid flow. Field examples are given to indicate the success and utility of the method. Of great importance to the operations engineer is the fact that job procedures with the well at normal operating conditions are standardized for ready field interpretation. Introduction With the increasing application of water flooding, pressure maintenance and other recovery-increasing techniques in the oil industry, an accurate means of determining input profiles is an absolute requirement. The injection fluid costs, especially in miscible floods and gas injection, are such that channeling behind the pipe must be located and remedied. Also, the efficiency of secondary recovery techniques requires orderly flood-front movement throughout the vertical extent of the zones. Therefore, the input profile must be as desired, and accurate profiling by some means is necessary on the injection wells after completion and at intervals during the flood. In some cases in waterflood projects, even input profiles are not the only requirement-the production profiles should also be such that orderly flood-front movement is obtained. Again, an accurate means of profiling is required at intervals during the project. There are a number of production problems where accurate production profiles can be of great aid in remedial work. Where wells are producing large amounts of water along with a small amount of oil from either long perforated intervals or open hole, shutting off the water section and allowing greater drawdown on the oil section can greatly increase oil production. In wells of this type, of course, are the condition where the highest permeability zones are watered out with oil remaining in the less permeable zones. JPT P. 851ˆ

There are few methods to acid stimulate cross-flowing zones in dump water injector wells. Traditionally these wells are stimulated by bull-heading acid from surface or pumping it through Coiled Tubing (CT). The dilution and contamination of the acid while being injected into the formation resulted in no increase in dumping injection rates. Poor post stimulation results are confirmed by spinner survey logs done before and after the conventional acid treatments. Through Tubing Inflatable Anchoring Packer (TTIAP), a new zonal isolation tool conveyed by coiled tubing was successfully used to selectively acidize the targeted zone by isolating the non-desired zones. TTIAP has an effective and reliable high pressure sealing properties at large inflation ratio. Its chemical resistance makes it ideal for selective placement of treating fluids, such as acid stimulation and water shut off fluids.<sup>1,2</sup> A non-polymeric Viscoelastic Surfactant based Self Diverting Acid (VES-SDA) system was successfully used to divert and effectively stimulate these vertical dump water injector wells by achieving uniform acid coverage across the whole perforated interval. The VES-SDA is a single stage fluid that has the capability to stimulate and divert in one step. This paper discusses the successful application of TTIAP as a mean of mechanical diversion in the well-bore area to isolate between the "S" aquifer and the "R" reservoir, while VES-SDA acid was used as a mean of chemical diversion inside carbonate formations. The injection evaluation logs showed significant injection rate increase after the new stimulation method. This study marks the first time such a combination was used to stimulate dump water injector wells with crossflowing zones in Saudi Arabia.

A new tool provides simultaneous recording of measurements from all downhole production-logging sensors used in the analysis of production or injection wells. The system was used to evaluate production-well profiles in the South Swan Hills miscible flood project in Alberta, Canada. The dynamic reservoir picture obtained from the information proved useful in improving reservoir performance. Introduction Production logs have been used for many years to Production logs have been used for many years to evaluate producing and injection wells. In the past, when reservoirs with excess capacity were limited by allowables, production logs were used basically to diagnose a problem on an individual well, such as locating a source of water production or defining a mechanical problem such as a packer leak. Today, with the increased demand for oil and the declining capacity of mature reservoirs, combined with more sophisticated recovery schemes, the oil industry is becoming increasingly aware of the importance of improving fieldwide reservoir performance. With this shift in emphasis, the role of production logging has taken on a much wider scope.For the evaluation and management of a reservoir, the reservoir engineer may get the information he needs by running production logs on selected production and injection wells throughout the production and injection wells throughout the reservoir. By repeating this on an appropriate time scale, a dynamic description of the reservoir can be evolved. This information can be integrated with formation evaluation logs, such as the TDT log and the initial openhole logs, to compare actual performance with indicated reservoir potential. performance with indicated reservoir potential. The analysis of producing wells is rarely simple. Downhole flow usually involves different fluids (oil, water, and gas) having different densities and moving at different velocities. Furthermore, these may vary with time because of well instability. Typically, several measurements are needed to resolve the problem. The effect of well instability can be reduced problem. The effect of well instability can be reduced by obtaining the measurements simultaneously. Much has been published in the literature on the use of flowmeter, thermometer, manometer, Gradiomanometer TM and caliper tools to analyze downhole flow. In addition, a casing-collar locator and a gamma-ray log are useful for depth control and correlation with the formation evaluation logs.In this paper we describe a new 1 11/16-in. (42.9-mm) diameter telemetry-based tool - the PLT (TM) (simultaneous production logging tool) - capable of transmitting all these measurements simultaneously during one trip in the well. It is relatively easy to add new sensors to this flexible system. A new dual tracer ejector tool and a high-precision pressure gauge, which have been added to the above family of sensors, also are discussed.This paper presents the results of a 15-well logging program in which the PLT tool was used to evaluate program in which the PLT tool was used to evaluate a miscible flood project in the South Swan Hills pool in Alberta, Canada. While tracer materials were used to monitor the lateral progress of the flood front, production logging was used to monitor the vertical production logging was used to monitor the vertical distribution in both injection and production wells. JPT P. 191

Oil wells typically have multiple concentric casing strings. For a set of two concentric strings, if the inner pipe has a compressive axial force, it will typically buckle within the outer string. The buckling of pipe can be important in the analysis of a well-completion design, as the buckled pipe can develop bending stresses that may be significant. Most analyses of this problem assume that the outer casing is rigid. In reality, this external casing is also elastic and would displace owing to the loads generated by contact with the inner pipe. Further, if both strings have compressive axial forces, both strings will buckle, and the resulting buckled configuration must fit together so that contact forces between the two strings are positive and the pipes do not each occupy the same space. If the two strings have an external, cylindrical rigid wellbore, then any contact forces with this wellbore must also be positive, and the buckled pipe system must lie within this wellbore. There is only one known solution to the multiple concentric pipe-buckling problem, that of Christman (Christman, 1976), who proposed a composite pipe based on the summed properties of the individual pipes. This analysis does not conform to the requirements posed in the previous paragraph. This paper presents the various ways that two concentric pipes can interact when one or both pipes are in compression and would then have a tendency to buckle. The contact forces between the pipes and with the external wellbore are explicitly calculated, and contact or non-contact conditions are determined. All results are analytic so that they can easily be used in spreadsheets or hand calculations. Several example calculations are presented to illustrate how these results might be used.

Summary Oil wells typically have multiple concentric casing strings. For a set of two concentric strings, if the inner pipe has a compressive axial force, it will typically buckle within the outer string. The buckling of pipe can be important in the analysis of a well-completion design because the buckled pipe can develop bending stresses that may be significant. Most analyses of this problem assume that the outer casing is rigid. In reality, this external casing is also elastic and would displace owing to the loads generated by contact with the inner pipe. Further, if both strings have compressive axial forces, both strings will buckle, and the resulting buckled configuration must fit together so that contact forces between the two strings are positive and the pipes do not each occupy the same space. If the two strings have an external, cylindrical rigid wellbore, then any contact forces with this wellbore must also be positive, and the buckled pipe system must lie within this wellbore. The only known solution to the multiple concentric pipe-buckling problem is that of Christman (1976), who proposed a composite pipe based on the summed properties of the individual pipes. This analysis does not conform to the requirements posed in the preceding paragraph. This paper presents the various ways that two concentric pipes can interact when one or both pipes are in compression and would then have a tendency to buckle. The contact forces between the pipes and with the external wellbore are explicitly calculated, and contact or noncontact conditions are determined. All results are analytical so that they can easily be used in spreadsheets or hand calculations. Several examples of calculations are presented to illustrate how these results might be used.

Since its discovery in 1969, the Ekofisk Area has developed into one of the most industrious oil centers in the North Sea. The Ekofisk Area presently encompasses twenty-five permanent platforms of which eleven are production/injection platforms with over 125 active wells. To date, 113 workovers have been performed on these wells. Production from the Ekofisk Area peaked on February 8, 1980, when 618,000 BOPD and 1,860 MMSCFD gas were produced. Development drilling activity peaked in late 1979 when there were ten active drilling or workover rigs on nine platforms. Today, there are four drilling and workover crews active in the area. Reservoir depletion and compaction and the resulting seabed subsidence have altered drilling and workover operations over the past six years. This paper discusses how current drilling and workover practices have evolved in the Ekofisk Area.