Monte carlo simulation using excel spreadsheet for predicting reliability of a complex system

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. ISBN Get permission for reuse. Casing and tubing strings are the main parts of the well construction.

Therefore, this chapter provides the basic knowledge for practical casing and tubing strength evaluation and design. Casing is the major structural component of a well.

Casing is needed to maintain borehole stability, prevent contamination of water sands, isolate water from producing formations, and control well pressures during drilling, production, and workover operations. Casing provides locations for the installation of blowout preventers, wellhead equipment, production packers, and production tubing. The cost of casing is a major part of the overall well cost, so selection of casing size, grade, connectors, and setting depth is a primary engineering and economic consideration.

Tubing is the conduit through which oil and gas are brought from the producing formations to the field surface facilities for processing. Tubing must be adequately strong to resist loads and deformations associated with production and workovers. Further, tubing must be sized to support the expected rates of production of oil and gas.

Clearly, tubing that is too small restricts production and subsequent economic performance of the well. Tubing that is too large, however, may have an economic impact beyond the cost of the tubing string itself because the tubing size will influence the overall casing design of the well. To design a reliable casing string, it is necessary to know the strength of pipe under different load conditions.

Burst strength, collapse resistance, and tensile strength are the most important mechanical properties of casing and tubing. While a number of joint connections are available, the API recognizes three basic types: Threads are used as mechanical means to hold the neighboring joints together during axial tension or compression.

For all casing sizes, the threads are not intended to be leak resistant when made up. The internal yield pressure is the pressure that initiates yield at the root of the coupling thread. This dimension is based on data given in API Spec. The coupling internal yield pressure is typically greater than the pipe body internal yield pressure. The internal pressure leak resistance is based on the interface pressure between the pipe and coupling threads because of makeup.

In round threads, two small leak paths exist at the crest and root of each thread. In buttress threads, a much larger leak path exists along the stabbing flank and at the root of the coupling thread.

API connections rely on thread compound to fill these gaps and provide leak resistance. The leak resistance provided by the thread compound is typically less than the API internal leak resistance value, particularly for buttress connections. The leak resistance can be improved by using API connections with smaller thread tolerances and, hence, smaller gapsbut it typically will not exceed 5, psi with any long-term reliability.

Applying tin or zinc plating to the coupling also results in smaller gaps and improves leak resistance. The round-thread casing-joint strength is given as the lesser of the fracture strength of the pin and the jump-out strength. The fracture strength is given by These equations are based on tension tests to failure on round-thread test specimens. Both are theoretically derived and adjusted using statistical methods to match the test data.

For standard coupling dimensions, round threads are pin weak i. The buttress thread casing joint strength is given as the lesser of the fracture strength of the pipe body the pin and the coupling the box. Pipe thread strength is given by These equations are based on tension tests to failure on buttress-thread test specimens. They are theoretically derived and adjusted using statistical methods to match test data. The improved performance of many proprietary connections results from one or more of these features not found in API connections: The "premium" performance of most proprietary connections comes at a "premium" cost.

Increased performance should always be weighed against the increased cost for a particular application. As a general rule, it is recommended to use proprietary connections only when the application requires them. Those conditions are tighter dimensional tolerance; plating applied to coupling; use of appropriate thread compound; and performance verified with qualification testing.

The performance of a proprietary connection can be reliably verified by performing three steps: When requesting tensile performance data, make sure that the manufacturer indicates whether quoted tensile capacities are based on the ultimate tensile strength i.

If possible, it is recommended to use the joint elastic limit values in the design so that consistent design factors for both pipe-body and connection analysis are maintained.

If only parting load capacities are available, a higher design factor should be used for connection axial design.

SREMS: System Reliability Using Monte Carlo Simulation with VBA and Excel: Quality Engineering: Vol 15, No 2

Most casing failures occur at connections. These failures can be attributed to improper design or exposure to loads exceeding the rated capacity; failure to comply with makeup requirements; failure to meet manufacturing tolerances; damage during storage and handling; and damage during production operations corrosion, wear, etc. Connection failure can be classified broadly as leakage; structural failure; galling during makeup; yielding because of internal pressure; jump-out under tensile load; fracture under tensile load; and failure because of excessive torque during makeup or subsequent operations.

Avoiding connection failure is not only dependent upon selection of the correct connection but is strongly influenced by other factors, which include manufacturing tolerances; storage storage thread compound and thread protector ; transportation thread protector and handling procedures ; and running procedures selection of thread compound, application of thread compound, and adherence to correct makeup specifications and procedures.

The overall mechanical integrity of a correctly designed casing string is dependent upon a quality assurance program that ensures damaged connections are not used and that operations personnel adhere to the appropriate running procedures. The design limits of a connection are not only dependent upon its geometry and material properties but are influenced by surface treatment; phosphating; metal plating copper, tin, or zinc ; bead blasting; thread compound; makeup torque; use of a resilient seal ring many companies do not recommend this practice ; fluid to which connection is exposed mud, clear brine, or gas ; temperature and pressure cycling; and large doglegs e.

As installed, casing usually hangs straight down in vertical wells or lays on the low side of the hole in deviated wells. Thermal or pressure loads might produce compressive loads, and if these loads are sufficiently high, the initial configuration will become unstable. However, because the tubing is confined within open hole or casing, the tubing can deform into another stable configuration, usually a helical or coil shape in a vertical wellbore or a lateral S-shaped configuration in a deviated hole.

These new equilibrium configurations are what we mean when we talk about buckling in casing design. In contrast, conventional mechanical engineering design considers buckling in terms of stability i. Accurate analysis of buckling is important for several reasons. First, buckling generates bending stresses not present in the original configuration. If the stresses in the original configuration were near yield, this additional stress could produce failure, including permanent plastic deformation called "corkscrewing.

Coiled tubing is shorter than straight tubing, and this is an important consideration if the tubing is not fixed. Third, tubing buckling causes the relief of compressive axial loads when the casing is fixed. This effect is not as recognized as the first two buckling effects but is equally important. The axial compliance of buckled tubing is much less than the compliance of straight tubing. Casing movement, because of thermal expansion or ballooning, can be accommodated with a lower increase in axial load for a buckled casing.

The accuracy and comprehensiveness of the buckling model is important for designing tubing. The most commonly used buckling solution is the model developed by Lubinski in the s.

This model is accurate for vertical wells but needs modification for deviated wells. This solution overestimates tubing compliance, which might greatly underestimate the axial loads, resulting in a nonconservative design. Buckling should be avoided in drilling operations to minimize casing wear.

Buckling can be reduced or eliminated by applying a pickup force before landing the casing; holding pressure, while weighing on cement WOCto pretension the string subsea wells ; raising the top of cement; using centralizers; and increasing pipe stiffness. In production operations, casing buckling is not normally a critical design issue.

However, a large amount of buckling can occur because of increased production temperatures in some wells. A check should be made to ensure that plastic deformation or corkscrewing will not occur.

This check is possible using triaxial analysis and including the bending stress because of buckling. Corkscrewing occurs only if the triaxial stress exceeds the yield strength of the material. Buckling is typically a more critical design issue for production tubing than for casing.

Tubing is typically exposed to the hottest temperatures during production. Tubing is less stiff than casing, and annular clearances can be quite large. Buckling can prevent wireline tools from passing through the tubing.

Buckling can be controlled by tubing-to-packer configuration latched or free, seal bore diameter, allowable movement in seals, etc. As in casing design, a triaxial check should be made to ensure that plastic deformation or corkscrewing will not occur.

Buckling occurs if the buckling force, F bis greater than a threshold force, F pknown as the Paslay buckling force. The buckling force, F bis defined as An important distinction between Eq. The equation for a dogleg curvature for a helix is The dogleg unit for Eq.

To convert to the conventional unit of degrees per ft, multiply the result by 68, Given the tubing curvature, the bending moment is determined by The following correlations can be derived with Eqs. The buckling "strain," in the sense of Lubinski, is the buckling length change per unit length. The buckling strain is given by The lateral buckling strain is roughly half the conventional helical buckling strain.

However, there are two special cases that are commonly used. For the case of constant force, F bsuch as in a horizontal well, Eq. The second special case is for a linear variation of F b over the interval. From equilibrium considerations only, the average contact force for lateral buckling is The tubing will buckle for any force between 6, lbf and 30, lbf.

Sample Buckling Bending Stress Calculations. The maximum bending stress, because of buckling, can be evaluated with Eq. This stress is fairly large compared to tubing yield strengths of about 80, psi, so buckling bending stresses can be important for casing and tubing design.

At the buckling load of 19, lbf, both helical and lateral buckling can occur. The lateral bending stress is given by Eq. This indicates that determination of buckling type can be important in casing design where casing strength is marginal.

Sample Buckling Length Change Calculations — Tubing Movement. Tubing length change calculations involve two calculations for this case, tubing movement because of lateral buckling and tubing movement because of helical buckling. A third calculation is made to show the movement because of pure helical buckling.

The lateral buckling tubing movement is given by The helical buckling tubing movement is given by The total tubing movement is 0. Pure helical buckling produces the length change, Tubing movement is a design consideration for packer selection. Seal length is an important criterion for tubing well completion design. When designing seal length in a deviated well, use of pure helical buckling can produce significant error.

In order to evaluate a given casing design, a set of loads is necessary. Casing loads result from running the casing, cementing the casing, subsequent drilling operations, production and well workover operations.

Casing loads are principally pressure loads, mechanical loads, and thermal loads. Pressure loads are produced by fluids within the casing, cement and fluids outside the casing, pressures imposed at the surface by drilling and workover operations, and pressures imposed by the formation during drilling and production. Mechanical loads are associated with casing hanging weight, shock loads during running, packer loads during production and workovers, and hanger loads.

Temperature changes and resulting thermal expansion loads are induced in casing by drilling, production, and workovers, and these loads might cause buckling bending stress loads in uncemented intervals. Next, we discuss casing loads that are typically used in preliminary casing design. However, each operating company usually has its own special set of design loads for casing, based on their experience.

If you are designing a casing string for a particular company, this load information must be obtained from them.

Because there are so many possible loads that must be evaluated, most casing design today is done with computer programs that generate the appropriate load sets often custom tailored for a particular operatorevaluate the results, and sometimes even determine a minimum-cost design automatically.

Pressure distributions are typically used to model the external pressures in cemented intervals. Fluid pressure is given by the mud gradient above the top-of-cement TOC and by the cement gradient below TOC. Again, fluid pressure is given by the mud gradient above TOC and by the cement gradient below TOC. The exception is that formation pore pressure is imposed over the permeable zone interval.

This pressure profile is discontinuous. Poor Cement, High Pressure. In this case, the formation pore pressure is felt at the surface through the poor cement. This pressure profile is continuous with depth. Poor Cement, Low Pressure. In this case, the mud surface drops so that the mud pressure equals the formation pressure. TOC Inside Previous Shoe. In this case, fluid pressure is given by mud gradient above TOC, cement gradient to the shoe, and the minimum equivalent mud weight gradient of the openhole below the shoe.

This pressure profile is not continuous with depth; it is discontinuous at the previous shoe. TOC Below Previous Shoe, Without Mud Drop. In this case, fluid pressure is given by the mud gradient above TOC and by the minimum equivalent mud weight gradient of the openhole below the shoe. This pressure profile is not continuous with depth but is discontinuous at TOC.

TOC Below Previous Show, With Mud Drop. In this case, the mud surface drops so that the mud pressure equals the minimum equivalent mud weight gradient of the openhole at the TOC. In this case, fluid pressure is given by mud gradient above TOC, cement gradient to the shoe, and a specified pressure profile below a specified depth.

This external pressure distribution may be discontinuous at the specified depth. If a pressure gradient is specified, the pressure profile may also be continuous at the specified depth. Pressure distributions are typically used to model the internal pressures. These pressure distributions are discussed next. It should represent the worst-case kick to which the current casing can be exposed while drilling a deeper interval. Typically, this means taking a kick at the total depth TD of the next openhole section.

If the kick intensity or volume cause the fracture pressure at the casing shoe to exceed, the kick volume is often reduced to the maximum volume that can be circulated out of the hole without exceeding the fracture pressure at the shoe.

The maximum pressure experienced at any casing depth occurs when the top of the gas bubble reaches that depth. This load case uses an internal pressure profile consisting of a gas gradient extending upward from a formation pressure in a deeper hole interval or from the fracture pressure at the casing shoe. This pressure physically represents a well control situation, in which gas from a kick has completely displaced the mud out of the drilling annulus from the surface to the casing shoe.

This is the worst-case drilling burst load that a casing string could experience, and if the fracture pressure at the shoe is used to determine the pressure profile, it ensures that the weak point in the system is at the casing shoe and not the surface.

This, in turn, precludes a burst failure of the casing near the surface during a severe well-control situation. This load case is a variation of the displacement-to-gas load case that has wide usage in the industry and is taught in several popular casing design schools.

It has been used historically because it results in an adequate design though typically quite conservative, particularly for wells deeper than 15, ftand it is simple to calculate. The interface is calculated on the basis of surface pressure typically equal to the BOP rating and the fracture pressure at the shoe and assuming a continuous pressure profile. Lost Returns With Water. This load case models an internal pressure profile, which reflects pumping water down the annulus to reduce surface pressure during a well-control situation in which lost returns are occurring.

The pressure profile represents a freshwater gradient applied upward from the fracture pressure at the shoe depth.

This load case typically dominates the burst design when compared to the gas-kick load case. This is particularly the case for intermediate casing. This load case is less severe than the displacement-to-gas criteria and represents a moderated approach to preventing a surface blowout during a well-control incident.

It is not applicable to liners. The same surface pressure calculated in the "lost returns with water" load case is used, but in this load case, a gas gradient from this surface pressure is used to generate the rest of the pressure profile. This load case represents no actual physical scenario; however, when used with the gas-kick criterion, it ensures that the casing weak point is not at the surface.

Typically, the gas-kick load case will control the design deep, and the surface-protection load case will control the design shallow, leaving the weak point somewhere in the middle. This load case models an internal pressure profile, which reflects a surface pressure applied to a mud gradient.

The test pressure typically is based on the maximum anticipated surface pressure determined from the other selected burst load cases plus a suitable safety margin. For production casing, the test pressure is typically based on the anticipated shut-in tubing pressure. This load case may or may not dominate the burst design depending on the mud weight in the hole at the time the test occurs.

The pressure test is normally performed prior to drilling out the float equipment. This load case models an internal and external pressure profile, which reflects the collapse load imparted on the casing after the plug has been bumped during the cement job and the pump pressure bled off.

The external pressure considers the mud hydrostatic column and different densities of the lead and tail cement slurries. The internal pressure is based on the gradient of the displacement fluid. If a light displacement fluid is used, the cementing collapse load can be significant. Lost Returns With Mud Drop. This load case models an internal pressure profile, which reflects a partial evacuation or a drop in the mud level because of the mud hydrostatic column equilibrating with the pore pressure in a lost-circulation zone.

The heaviest mud weight used to drill the next openhole section should be used along with a pore pressure and depth that result in the largest mud drop. Many operators make the conservative assumption that the lost-circulation zone is at the TD of the next openhole section and is normally pressured.

A partial evacuation of more than 5, ft, because of lost circulation during drilling, is normally not seen. Many operators use a partial evacuation criterion in which the mud level is assumed to be a percentage of the openhole TD. This load case should be considered when drilling with air or foam.

It may also be considered for conductor or surface casing where shallow gas is encountered. This load case would represent all of the mud being displaced out of the wellbore through the diverter before the formation bridged off.

For wells with a sufficient water supply, an internal pressure profile consisting of a freshwater or seawater gradient is sometimes used as a collapse criterion. This assumes a lost-circulation zone that can only withstand a water gradient. Gas Migration Subsea Wells.

This load case models bottomhole pressure applied at the wellhead subject to fracture pressure at the shoe from a gas bubble migrating upward behind the production casing with no pressure bleedoff at the surface. The pressure is the minimum of the fracture pressure at the shoe and the reservoir pressure plus the mud gradient.

The load case has application only to the intermediate casing in subsea wells where the operator has no means of accessing the annulus behind the production casing. This load case applies to both production and injection operations and represents a high surface pressure on top of the completion fluid because of a tubing leak near the hanger. A worst-case surface pressure is usually based on a gas gradient extending upward from reservoir pressure at the perforations.

If the proposed packer location has been determined when the casing is designed, the casing below the packer can be assumed to experience pressure, based on the produced fluid gradient and reservoir pressure only. This load case applies to wells that experience high-pressure annular injection operations such as a casing fracture stimulation job. The load case models a surface pressure applied to a static fluid column.

This is analogous to a screenout during a frac job. This severe load case has the most application in gas lift wells. It is representative of a gas filled annulus that loses injection pressure. Many operators use the full evacuation criterion for all production casing strings regardless of the completion type or reservoir characteristics.

This load case is based on a hydrostatic column of completion fluid equilibrating with depleted reservoir pressure during a workover operation. Some operators do not consider a fluid drop but only a fluid gradient in the annulus above the packer. This is applicable if the final depleted pressure of the formation is greater than the hydrostatic column of a lightweight packer fluid. This load case applies to severely depleted reservoirs, plugged perforations, or a large drawdown of a low-permeability reservoir.

It is the most commonly used collapse criterion. This load case assumes zero surface pressure applied to a fluid gradient. A common application is the underbalanced fluid gradient in the tubing before perforating or after if the perforations are plugged.

It is a less conservative criterion for formations that will never be drawn down to zero. This load case models bottomhole pressure applied at the wellhead subject to fracture pressure at the prior shoe from a gas bubble migrating upward behind the production casing with no pressure bleedoff at the surface. The pressure distribution is the minimum of the following two pressure distributions. The load case has application only in subsea wells where the operator has no means of accessing the annulus behind the production casing.

An internal pressure profile consisting of a completion fluid gradient is typically used. If a formation that exhibits plastic behavior, such as a salt zone, is to be isolated by the current string, then an equivalent external collapse load typically taken to be the overburden pressure should be superimposed on all of the collapse load cases from the top to the base of the salt zone.

In offshore wells with sealed annuli, increases in fluid temperatures caused by production will cause fluid expansion, resulting in increased fluid pressures. Fortunately, the casing and formation are sufficiently elastic to greatly reduce this pressure.

The equilibrium pressure produced by thermal expansion must be calculated to balance fluid volume change with annular volume change. Nevertheless, the annular pressure change produced by thermal expansion has proved to be a serious design consideration, especially in the North Sea and in deep water. In tubing and over the free length of the casing above TOC, changes in temperatures and pressures will have the largest effect on the ballooning and temperature load components. The incremental forces, because of these effects, are given here.

This installation load case represents the maximum axial load that any portion of the casing string experiences when running the casing in the hole. It can include effects such as: This installation load case models an incremental axial load applied at the surface while running the pipe in the hole.

Casing designed using this load case should be able to withstand an overpull force applied with the shoe at any depth if the casing becomes stuck while running in the hole. Certain effects must be considered, such as self-weight; buoyancy forces at the end of the pipe and at each cross-sectional area change; wellbore deviation; bending loads superimposed in dogleg regions; frictional drag; and the applied overpull force.

This installation load case models applying surface pressure after bumping the plug during the primary cement job. Because the cement is still in its fluid state, the applied pressure will result in a large piston force at the float collar and often results in the worst-case surface axial load. The effects that should be considered are self-weight; buoyancy forces at the end of the pipe and at each cross-sectional area change; wellbore deviation; bending loads superimposed in dogleg regions; frictional drag; and piston force because of differential pressure across float collar.

Air Weight of Casing Only. This axial load criterion has been used historically because it is an easy calculation to perform, and it normally results in adequate designs. It still enjoys significant usage in the industry. Because a large number of factors are not considered, it is typically used with a high axial design factor e. Buoyed Weight Plus Overpull Only. Like the air weight criterion, this load case has wide usage because it is an easy calculation to perform. Shock loads can occur if the pipe hits an obstruction or the slips close while the pipe is moving.

The maximum additional axial force, because of a sudden deceleration to zero velocity, is given by the equation, The shock load equation is often expressed as For practical purposes, some operators specify an average velocity in this equation and multiply the result by a factor that represents the ratio between the peak and average velocities typically 1. For most wells, installation loads will control axial design. However, in wells with uncemented sections of casing and where large pressure or temperature changes will occur after the casing is cemented in place, changes in the axial load distribution can be important because of effects such as self-weight; buoyancy forces; wellbore deviation; bending loads; changes in internal or external pressure ballooning ; temperature changes; and buckling.

This bending stress can be expressed as an equivalent axial force as The bending load is superimposed on the axial load distribution as a local effect. In shallow normal-pressured wells, temperature will typically have a secondary effect on tubular design. In other situations, loads induced by temperature can be the governing criteria in the design.

Next, we discuss fastest way to get money in borderlands 2 temperature can affect tubular design.

Annular Fluid Expansion Pressure. Increases in temperature after the casing is landed can cause thermal expansion of fluids in sealed annuli and result in significant pressure loads. Most of dax and ftse stock markets yahoo time, these loads need not be included in the design because the pressures can be bled off.

However, in subsea wells, the outer annuli cannot be accessed after the hanger is landed. The pressure increases will also influence the axial load profiles of the casing strings exposed to the candles on the charts binary options because of ballooning effects.

Changes in temperature will increase or decrease tension in the casing string because of thermal contraction forex market trading software free download india expansion, respectively. The increased axial load, because of pumping cool fluid into the wellbore during a stimulation job, can be the critical axial design criterion.

In contrast, the reduction in how to make money gambling in vegas during production, because of thermal expansion, can increase buckling and possibly result in compression at the wellhead.

Changes in temperature not only affect loads but also influence the load resistance. Sour Gas Well Design. In sour environments, operating temperatures can determine what materials can be used at different depths in the wellbore. Produced temperatures in gas wells will influence the gas gradient inside the tubing because gas density is a function of temperature and pressure. To design a casing string, one must know the purpose of the well, the geological cross section, available casing and bit sizes, cementing and drilling practices, rig futures trading margin account, as well as safety and environmental regulations.

To arrive at the optimal solution, the design engineer must consider casing as a part of a whole drilling system. A brief description of the elements involved in the design process is presented next. The engineer responsible for developing the well plan and casing design is faced with a number of tasks that can be briefly characterized.

While the intention is to provide reliable well construction at a minimum cost, at times failures occur. Most documented failures occur because the pipe was exposed to loads for which it was not designed. These failures monte carlo simulation using excel spreadsheet for predicting reliability of a complex system called "off-design" failures. This implies that casing-design practices are mostly conservative.

Many failures occur at connections. This implies that either field makeup practices are not adequate or the connection typing jobs from home in allahabad basis is not consistent with the pipe-body design basis.

The design process can be divided into two distinct phases. Typically the largest opportunities for saving money are present while performing this task. This design phase includes data gathering and interpretation; determination of casing shoe depths and number of strings; selection of hole and casing sizes; mud-weight design; and directional design.

The quality of the gathered data will have a large impact on the appropriate choice of casing sizes and shoe depths and whether the orient manufacture and trading joint stock company design objective is successfully met. The detailed design phase includes: Selection of pipe weights and grades for each casing string.

The selection process consists of comparing pipe ratings with design loads and applying minimum acceptable safety standards i. A cost-effective design meets all the design criteria with the least expensive available pipe. The purpose of preliminary design is to establish casing and corresponding do bollinger bands tell you sizes, casing setting depths and, consequently, the number of casing strings.

Casing program well plan is obtained as a result of preliminary design. Casing program design is accomplished in three major steps. First, mud program is prepared; second, the casing sizes and corresponding drill-bit sizes are determined; and next, the setting depths of individual casing strings are found. The most important mud program parameter used in casing design is the "mud weight.

There are several things to observe about these two methods. First, they do not necessarily mo livestock auction reports the same setting depths. Second, they do not necessarily give the same number of strings.

In the top-down design, the bottomhole pressure is missed by a slight amount that requires a short 7-in. This slight error can be fixed by resetting the surface casing depth. The top-down method is more like actually drilling a well, in which the casing is set when necessary to protect the previous casing shoe.

This analysis can help anticipate the need for additional strings, given that the pore pressure and fracture gradient curves have some uncertainty associated picking a stock broker them.

In practice, a number of regulatory requirements can affect shoe depth design. These factors are discussed next. This can get select option value using jquery a function of mud weight, deviation and stress at the wellbore wall, or can be chemical in nature. Often, hole stability problems asx trading broker time-dependent behavior making shoe selection a function of penetration rate.

The plastic flowing behavior of salt zones must also be considered. The probability of becoming differentially stuck increases with increasing slumdog forex review pressure between the wellbore and formation, increasing permeability of the formation, and increasing fluid loss of the drilling fluid i.

Shallow freshwater sands must be isolated to prevent contamination. Lost-circulation zones must be isolated before a higher-pressure formation is penetrated.

A casing string is often run after an angle building section has been drilled. This avoids keyseating problems in the curved portion of the wellbore because of the increased normal force between the wall and the drillpipe.

Uncertainty in Predicted Formation Properties. Exploration livestock marketing specialist salary often require additional strings to compensate for the uncertainty in the pore pressure and fracture gradient predictions. Another approach that could be used for determining casing setting depths relies on plotting formation and fracturing pressures vs.

This procedure, however, typically yields many strings and is considered to be very conservative. See the chapter on geoscience principles in this volume of the handbook.

Exercising a stock option depths for each casing string should be selected in the preliminary design phase because this selection will influence axial load distributions and external pressure profiles used calculating cost basis of stock options the detailed design phase.

TOC depths are typically based on zonal isolation; regulatory requirements; prior shoe depths; formation strength; buckling; and annular pressure buildup in subsea wells. Buckling calculations are not performed until the detailed design phase. Hence, the TOC depth may be adjusted, as a result of the buckling analysis, to help reduce buckling in some cases. For casing design purposes, establishing a directional plan consists of determining the wellpath from the surface to the geological targets.

Earn money with surfer directional plan influences all aspects of casing design including mud weight and mud chemistry selection for hole stability, shoe seat selection, casing axial load profiles, casing wear, bending stresses, and buckling. It is based cotizacion apple forexpros factors that include geological targets; surface location; interference from other wellbores; torque and drag considerations; casing wear considerations; bottomhole assembly [ BHA an assembly of drill collars, stabilizers, and bits]; and drill-bit performance in the local geological setting.

To account for the variance from the planned build, drop, and turn rates, which occur because of the BHAs used and operational practices employed, higher doglegs are often should i buy or sell boeing stock over the wellbore.

This increases the calculated bending stress in the detailed design phase. In order to select appropriate weights, trading currency for dummies ebook, and connections during the detailed design phase using sound engineering judgment, design criteria must be established.

These criteria normally consist of load cases and their corresponding design factors that part time telesales jobs working from home compared to pipe ratings. Load cases are typically placed into categories that include burst loads; drilling loads; production loads; collapse loads; axial loads; running and cementing loads; and service loads.

As long as the rating is greater than or forex broker finance to the modified load which we will call the design loadthe design criteria have been satisfied. After performing a design based on burst, collapse broker commission stock sale axial considerations, an initial design is achieved.

Before a final design is reached, design issues connection selection, wear, and corrosion must be addressed. In addition, other considerations can also be included in the design. These considerations are big name in the stock market crossword clue stresses because of combined loading e.

In the examples that are discussed next, burst, collapse, and uniaxial tension failure criteria are examined. Triaxial stresses are calculated for a variety of load situations to demonstrate how the casing strength formulas and the load formulas are actually used.

The burst differential pressure for this casing is given by Eq. The load case we will test against is the burst displacement-to-gas case, with formation pressure of 6, psi, formation depth at 12, ft, and gas gradient equal to 0. According to this calculation, the casing is strong enough to resist this burst pressure.

As an additional test, let us calculate the von Mises stress associated with this case. Surface axial stress is the casing weight chipotle stock market history by the cross-sectional area The radial stresses for the internal expensing of stock options external radii are the internal and external pressures.

The von Mises equivalent stress or triaxial stress synthetic stock for remington 11-87 given as Eq. Thus, the burst calculation is conservative compared to the von Mises calculation for this case. The collapse pressure for this liner is calculated from Eq.

The collapse pressure is then given by Penipuan bisnis online forex evaluate the collapse of this liner, we need internal and external pressures. Internal pressure is determined with the full evacuation above packer. The external pressure is based on a fully cemented section behind the 7-in.

An equivalent pressure is calculated from p i and p o for comparison with the collapse pressure, p cthrough use of Eq. Because p e exceeds p c 4, psithe liner is predicted to collapse. It is not appropriate to calculate a von Mises stress for collapse in this case because collapse in the transitional region is not strictly a plastic yield condition.

The hanging weight in air for the casing is The casing stress at the surface is F air divided by the cross-sectional area of the casing, less the hydrostatic pressure at the bottom of the let make money documentary erwin wagenhofer when cemented.

Next, consider the effects of a stimulation treatment on this surface stress. The change in axial stress, because of this temperature increase, is given by Eq. The net surface stress in the casing is. Most of the discovery wells in the Prudhoe Bay field were lost because of the reviews of hargreaves lansdown stockbrokers of annular fluids.

This failure mode is called internal freeze-back, to distinguish it from the refreezing of the permafrost, called external freeze-back. The solution to internal freeze-back is to replace freezeable fluids in the annuli with nonfreezeable fluids, such as oil-based fluids or alcohol-based fluids, such as glycol.

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Complete displacement of water-based fluids is essential for successful mitigation of internal freeze-back. Experience has shown that a cement system used for permafrost cementing must meet a minimum set of requirements:. As with any cementing system, once the slurry is in place, the major consideration anz investment options system design becomes long-term performance of the cement.

Experience with permafrost cementing has shown the value of using high-alumina cements for this application. Through the use of chemical extenders and freeze depressants, a high-alumina cement can be used to make a permafrost cement system. The system exhibits heat of hydration high enough to enhance the setting process.

However, the large quantity of water in an extended system absorbs heat generated during hydration, eliminating the need for fly ash. A high-alumina cement cannot be blended with Portland cement because blending the two causes extreme acceleration of the high-alumina cement, resulting in severe gelation or "flash" setting. Operators must use extreme caution to prevent contamination of a high-alumina cement system with Portland cement. The chance best way to earn money in aqw contamination can be minimized with astringent cleaning of field bins, bulk trucks, and storage facilities before and after each job using a high-alumina cement system.

However, under normal operations, it becomes almost impossible to eliminate the chance of alumina cement and Portland cement contacting each other. A permafrost cementing system using Portland cement and appropriate forex kiss terminator reviews additives eliminates the chance of this problem occurring. An extended Class G permafrost cement may offer the same performance as the high-alumina cement except that it is compatible with conventional permafrost tail-in online dtp work from home in hyderabad systems, whereas the high-alumina cement is not.

The extended Class G system eliminates the storage and handling problems previously associated with a high-alumina cement system. These attributes make an extended system using Class G Portland cement more cost effective faq forex market a high-alumina cement system.

This analytical freeze-back model and its correlation with freeze-back field-test data from Prudhoe Bay yielded the conclusions that are listed next. Oilfield tubulars have been traditionally designed using a deterministic working stress design WSD approach, which is based on multipliers called safety factors SFs.

The primary role of a safety factor is to account for uncertainties in the design variables and parameters, primarily the load effect and the strength or resistance of the structure.

While based on experience, these factors give no indication of the probability of failure of a given structure, as they do not explicitly consider the randomness of the design variables and parameters. Moreover, the forexperu comentarios factors tend to be rather conservative, and most limits of design are established using failure criteria based on elastic theory. In contrast, reliability-based approaches are probabilistic in nature and explicitly identify all the design variables and parameters that determine the load effect and strength of the structure.

Moreover, they use a limit-states approach to the design of tubulars, rather than elasticity-based initial yield timely stock market indicators to predict structural failure. Such probabilistic design methodologies allow either the computation of the probability of failure P f of a given structure or the design of a structure that meets a target probability of failure.

Reliability-based techniques have been formally applied to the design of load-bearing structures in several disciplines. However, their application to the design of oilfield tubulars is relatively new. Two different reliability-based approaches have been considered: Comparison of SF to the estimated design reliability offers a reliability-based interpretation of WSD and gives insight into the design reliabilities implicit in WSD.

In all design procedures, a primary goal is to ensure that the total load effect of the applied loads is lower than the strength of the tubular to withstand that particular load effect, given the uncertainty in the estimate of the load effect, resistance, and their relationship.

The load effect is related to the resistance of the tubular by means of a relationship, often known as the "failure criterion," which is thought to represent the limit of the tubular under that particular load effect. Thus, the failure criterion is specific to the response of the tubular to that load effect. Three conventional design procedures are considered: WSD, QRA, and LRFD. Clearly, the relationship between the load effect and resistance and the means of ensuring safety or reliability are different in each of these procedures.

In what follows, z i are the variables and parameters such as tension, pressure, diameter, yield stress, etc. WSD is the conventional casing design procedure, as discussed earlier in this chapter, that is, the familiar deterministic approach to the design of oilfield tubulars. In WSD, the load effect is separated from the resistance by means of an arbitrary multiplier, the SF. Indicator for binary options estimated load effect is often the worst-case load, Q wbased on deterministic design values for the parameters, z ithat determine the load effect.

The estimated resistance is often the minimum resistance, R minbased on deterministic design values for the parameters that determine the resistance. The design values chosen in formulating the resistance are such that the resulting resistance is a minimum. In most cases, the limits of design are established using failure criteria based on elastic theory. In some cases, such as collapse, WSD employs empirical savage axis 308 aftermarket stock criteria.

In general, the design procedure can be represented by the relationship The role of the SF is to account for uncertainties in the etf options brokers variables and parameters, primarily the load effect and the strength or resistance of the structure. The magnitude of the SF is usually based on experience, though little documentation exists on their origin or impact.

Different companies use different acceptable SFs for their tubular design. SFs give little indication of the probability of failure of a given structure, as they do not explicitly consider the randomness of the design variables and parameters. Some other limitations of this approach are listed in brief next. Thus, the probability that any given design may fail can be estimated, given an appropriate limit state and estimated magnitude and uncertainty of each of the basic variables and a reliability analysis tool.

The approach previously mentioned, although simple in concept, is usually difficult to implement in practice. First, the LSF is not always a manageable function and is often cumbersome to use.

Second, the uncertainty in the load and resistance parameters must be estimated each time a design is attempted. Third, the probability of failure must be estimated with an appropriate reliability analysis tool. It is tempting to treat each of the parameters, Z ias normal variates and use a first-order approach to the propagation of uncertainty. However, such an analysis would be in error because the variables are usually not normal, and first-order propagation gives reliable information only on the central tendencies of the resultant distributions and is erroneous in estimating the easy money making runescape 2016 probabilities.

Therefore, it is important to do a full Monte Carlo simulation to estimate the probability of failure of any real design with real variables. Clearly, this is a computer-intensive effort.

See the chapter on risk assessment in Emerging and Peripheral TechnologiesVol. VI of this Handbookfor more discussion on the Monte Carlo method. Load and Resistance Factor Design. The load and resistance factor design approach is a reliability-based approach that captures the reliability information characteristic of quantitative risk assessment and presents it in call forwarding settings samsung galaxy s3 mini design format far more amenable to routine use, just like WSD.

The limit state is the same as the one considered by QRA. However, the design approach is simplified essay about stock market crash the use of a design check equation DCE. LRFD allows the designer to check a design using a simplified DCE.

The DCE is usually chosen to be a simple and familiar equation for instance, the von Mises criterion in tubular design. Appropriate characteristic values of the design parameters are used in the DCE, along with partial factors that account for the uncertainties in the load and resistance and the difference between the DCE and the actual limit state. Thus, if Q char z i and R char how to make money selling antiques on ebay irespectively, represent the characteristic value of the load effect and of resistance, with z i being the characteristic values of each of the parameters and money making guide p2p osrs, the DCE can be represented by the inequality In the literature, LF and RF are usually referred to as the load factor and resistance factor, respectively.

The LF takes into account the uncertainty and variability in load effect estimation, while the RF takes into account the uncertainty and variability in the determination of resistance, as well as any difference between the LSF and DCE. Any design that satisfies Eq. The design check equation can be functionally identical to the LSF, or the functional relationship can be a simple formula specified by the design code or familiar WSD formulas.

In practice, it might not be possible to separate the load effects and resistance in the way suggested by Eq. Moreover, several load effects and resistance terms may be present in the DCE, with varying uncertainties, requiring the use of several partial factors.

We observe, from Eq. Thus, in concept, it may be said that First, the loads and resistances are estimated using a set methodology. Second, the load effect and the resistance are treated separately, thus allowing the partial factors to separately account for the uncertainties in each. And third, the magnitude of loads and resistances is based on reliability, rather than being arbitrarily set. Partial factors are chosen through a process of calibration, where the deterministic DCE with partial factors is calibrated against the probabilistic LSF.

Partial-factor values are chosen such that their use in the DCE results in a design that has a preselected target reliability or target probability of failure, as determined from the LSF using reliability analysis.

For the partial factors to do so, the calibration process should prescribe a scope of the application of LRFD, and the values of the partial factors should be optimized to ensure a uniform reliability across the scope.

The objective is to obtain a set of factors that results in designs of this target probability. In brief, the procedure may be summarized as follows.

First, choose a desired target probability of failure. Second, identify the characteristic values of each of the parameters, and the uncertainty and variability about these values.

Third, for an assumed set of load and resistance factors, generate a set of "passed" designs how to put puppies up for adoption sims 3 the DCE, across the scope of the structure, for all possible load magnitudes. In other words, all designs that pass the DCE are valid designs. The passing of a design is, of course, controlled by the assumed value of the load and resistance factors.

Fourth, for each of the passed designs, estimate the probability of failure from the LSF, taking into account the uncertainty in each of the variables. Fifth, determine the statistical minimum reliability assured by the assumed set of load synthetic stock for remington 11-87 resistance factors. This is the reliability or equivalently, probability of failure that results from the use of these partial factors.

In other words, the probability of failure of any design that results from the use of these partial factors in the DCE will, benefits of stock brokers in kenya, be less than or equal to the probability of failure.

Sixth, repeat until the set of partial factors results in the desired target probability of failure. At the end of the process, we have a set of partial factors and their corresponding design reliability. If several target reliabilities are to be aimed for, the procedure is repeated, until a new set of partial factors is obtained.

It must be noted that this is a very brief summary of the approach. Calibration is usually the most time-consuming and rigorous step in devising an LRFD procedure. Several reliability-theory and statistical details such as uncertainty estimation, preprocessing of high-reliability designs, zonation, uniformity of reliability, multiple partial factor calibration, etc.

WSD has been used successfully for many years to design casing. It is a simple system, understood by the average drilling engineer, of comparing a calculated worst-case load against the rating of the casing. The safety factors used may neither be based on strict logic nor be the same across industry, but the concept is simple and the numbers are similar. Generally, the system has served the industry well.

Risk-based design advocates criticize WSD because the failure models do not always use the ultimate load limit as the failure criterion, but this is not inherent to WSD. In an ideal world, where casing is always within specification, using average safety factors and worst-case estimates of loads, the casing should always be overdesigned. However, WSD makes no allowance for casing manufactured below minimum specification.

The SF used may or may not compensate for the fact that a below-strength joint is in a critical location. The risks cannot be quantified, so there is no way of comparing the relative risks of different designs. It can also lead to a situation in which it is impossible to produce a practical design under extreme downhole conditions. There would be a temptation in this case either to try to justify a reduction in the SF, perhaps by relying on improved procedures, or to re-estimate the loads downward.

Also, the system does not usually consider low levels of H 2 S, causing brittle failure in burst. Improvements such as better quality control, more accurate failure equations, and considering brittle burst could be utilized within a WSD system.

It is reasonable for the nonstatistician to accept that the strengths of joints of casing of the same weight and grade from the same mill will vary symmetrically around a mean value. The product is manufactured from nominally the same materials and by the same process, with the aim of producing identical properties. The predictability of the "resistance" side of the equation has been confirmed by large-scale examination and testing of the finished product.

The "load" side of the equation, such as formation pressures and kick volumes, may not be so predictable. There is also a much smaller data bank available for estimating probabilities. Further, human factors may influence the size of a kick by such things as speed of reaction in closing the well in and choosing the correct choke pressures when killing a kick.

The designer using risk-based casing design, thus has the same problem that the WSD user has—namely, which loads to consider in the design. The risk-based designer has an additional task, the assignment of probabilities to these loads. One could argue further that these loads should be weighted according to the severity of the resulting failure. If risk-based design systems are used by people who do not understand the system, or only use partial factors rather than the full system, wells will not be safer.

A risk-based design system with more accurate failure equations; account taken of brittle fracture in low levels of H 2 S; improved quality control of tubulars and connections; accurate load data; engineers who understand the system and the well; and a full training and competence assurance program may produce wells that are as safe as those designed using WSD.

An Investigation Into the Application of QRA in Casing Design. Presented at the SPE Applied Technology Workshop on Risk Based Design of Well Casing and Tubing, The Woodlands, Texas, USA, May. Impact on Casing Design of Thermal Expansion of Fluids in Confined Annuli.

Casing System Risk Analysis Using Structural Reliability. On the Development of Reliability-Based Design Rules for Casing Collapse. Presented at the Seventh Offshore Drilling Technology Conference, Aberdeen, November. Paper presented at the Seminar of Norwegian HPHT Programme, Stavanger, November.

Probability Concepts in Engineering Planning and Design: Decision, Risk and ReliabilityVol. Reliability Considerations in Design of Steel and CRA Production Tubing Strings. Presented at the SPE Health, Safety and Environment in Oil and Gas Exploration and Production Conference, The Hague, Netherlands, November.

Cementing Through Permafrost Environment. Paper presented at the ASME Energy Technology Conference and Exhibit, Houston. A New Low-Cost Permafrost Cementing System. Presented at the SPE California Regional Meeting, San Francisco, March. Load and Resistance Factor Design Case Histories. Presented at the Offshore Technology Conference, Houston, May.

Tubing and Casing Buckling in Horizontal Wells includes associated papers and CIRIA Report 63, Rationalisation of Safety and Serviceability Factors in Structural Codes. Construction Industry Research and Information Association. Cementing Through the Permafrost.

Paper presented at the ASME Energy Technology Conference and Exhibit, Houston, 18—22 September. Arctic Cements And Cementing. Field Investigation of Effect of Thawing Permafrost Around Wellbores at Prudhoe Bay. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Las Vegas, Nevada, USA, 30 September-3 October. Drill Pipe Buckling in Inclined Holes. Rules for the Design, Construction and Inspection of Offshore Structures.

EUROCODE 3, Common Unified Rules for Steel Structures. Commission of the European Communities. Materials for Wellheads and Christmas Trees for Cold Climates.

Paper presented at the Petroleum Mechanical Engineering Conference, Tulsa, Oklahoma, USA, September. Properties of Steel for Use in LRFD. Assessment of Current Design Practice. Loading Mechanisms in Thawed Permafrost around Arctic Wells. Paper presented at the ASME Energy Technology Conference and Exhibition, Houston, September. Mechanical properties of simulated deep permafrost. A Mechanical Model for Permafrost Freeze-Back Pressure Behavior.

Casing Design for Trapped Annular Pressure Buildup.

Multi-String Casing Design with Wellhead Movement. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, USA, March. Movement, Forces, and Stresses Associated With Combination Tubing Strings Sealed in Packers. J Pet Technol 29 2: Packer-to-Tubing Forces for Intermediate Packers. Health and Safety Executive: A Guide to the Offshore Installations Safety Case Regulationsfirst edition. A Guide to the Wells Aspects of the Offshore Installations and Wells Design and Construction, etc.

Regulationsfirst edition. Will Risk Based Casing Design Mean Safer Wells? Temperature Calculations for Wells Which Are Completed Through Permafrost.

Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, San Antonio, Texas, USA, October. Evaluation of Permafrost With Logs. Presented at the SPWLA 16th Annual Logging Symposium, SPWLAAA. Applying Quantitative Risk Assessment to Casing Design. The Advanced Theory of Statistics, Vol. A Rational Characterization of Proprietary High Collapse Casing Grades.

Presented at the SPE Annual Technical Conference and Exhibition, Dallas, October. A Service-Life Model for Casing Strings. SPE Drill Eng 1 2: Thermistor Cables Monitor Well Temperatures Effectively Through Permafrost. Gypsum-Cement Blend Works Well in Permafrost. Load and Resistance Factor Design for Oil Country Tubular Good. Simulation of Permafrost Thaw Behavior at Prudhoe Bay.

Load and Resistance Factor Design Specification for Structural Steel Buildings. American Institute of Steel Construction. Helical Buckling of Tubing Sealed in Packers. J Pet Technol 14 6: The Origin of Massive Icy Beds in Permafrost, Western Arctic Coast, Canada. Methods of Structural Safety. Upper Saddle River, New Jersey: International Series in Civil Engineering and Engineering Mechanics, Prentice-Hall. Cementing Materials for Cold Environments.

Pet Tech 23 Methods for Statistical Analysis of Reliability and Life Data. Manual for Steel Construction, Load and Resistance Factor Design. Insulated Hot Oil-Producing Wells In Permafrost. Pet Tech 27 3: Real World Implementation of QRA Methods in Casing Design. Minimum Design Loads for Buildings and Other Structures, ANSI A American National Standards Institute. An Analysis of Helical Buckling of Tubulars Subjected to Axial and Torsional Loading in Inclined Wellbores.

Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, USA, 2—4 April. A Mechanical Model for Permafrost Thaw Subsidence. Buckling Analysis in Deviated Wells: Forces on Curved Tubulars Caused By Fluid Flow. New Concepts for Helical Buckling. SPE Drill Eng 3 3: Permafrost Thaw-Subsidence Casing Design. One-dimensional Consolidation of Thawing Soils. Canadian Geotechnical Journal 8 4: Evaluation of Cement Systems for Permafrost.

Presented at the Annual Meeting of the American Institute of Mining, Metallurgical, and Petroleum Engineers Denver, February. National Building Code of Canada. Associate Committee on the National Building Code. Practical Extensions to a Theory of Consolidation for Thawing Soils. Second International Conference, Yakutsk, USSR. Application of QRA Methods to Casing Seat Selection. Presented at the European Petroleum Conference, London, October. Application of Probabilistic Reliability Methods to Tubular Designs.

SPE Drill Eng 5 4: Prudhoe Bay Field Permafrost Casing and Well Design for Thaw-Subsidence Protection. Report to State of Alaska, Atlantic Richfield Co. Studies of Pressures Generated Upon Refreezing of Thawed Permafrost Around a Wellbore.

Pet Tech 26 Pet Tech 22 7: Temperature Simulation While Drilling Permafrost. Paper presented at the CIM Annual Technical Meeting of the Petroleum Society, Banff, Alberta, Canada. Structural Reliability Under Combined Random Load Processes.

Computers and Structures 9: A Comparison of Deterministic and Reliability-Based Design Methodologies for Production Tubing. Implementation of a Reliability-Based Design Procedure for Production Tubing. Paper presented presented at the Offshore Mediterranean Conference, Ravenna, Italy, March. Recommendations for Loading and Safety Regulations for Structural Design. Investigation of Arctic Offshore Permafrost Near Prudhoe Bay. Paper presented at the Petroleum Mechanical Engineering and Pressure Vessels and Piping Conference, Mexico City, 19—24 September.

RP2A-LRFD, Recommended Practice for Planning, Design and Construction of Fixed Offshore Platformsfirst edition. Casing Strain Resulting From Thawing of Prudhoe Bay Permafrost. Pet Tech 30 3: Precise Joint Length Determination Using A Multiple Casing Collar Locator Tool. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Houston, October. Analysis and Design of Production Wells Through Thick Permafrost. Sample Disturbance and Thaw Consolidation of a Deep Sand Permafrost.

Structural Reliability Theory and its Applications. Theory of Elasticitythird edition. Partial Factor Calibration for North Sea Adaptation of API RP2A-LRFD.

Pet Tech 28 Pet Tech 29 4: Join SPE Log in About Help. Petroleum Engineering Handbook Larry W. Volume II - Drilling Engineering. CopyrightSociety of Petroleum Engineers. Chapter 7 - Casing Design. Mitchell, Landmark Graphics Pgs. Casing Casing is the major structural component of a well. Casing Strings There are six basic types of casing strings. Each is discussed next.

Conductor casing is the first string set below the structural casing i. The conductor isolates unconsolidated formations and water sands and protects against shallow gas. This is usually the string onto which the casing head is installed.

A diverter or a blowout prevention BOP stack may be installed onto this string. When cemented, this string is typically cemented to the surface or to the mudline in offshore wells. Surface casing is set to provide blowout protection, isolate water sands, and prevent lost circulation.

It also often provides adequate shoe strength to drill into high-pressure transition zones. In deviated wells, the surface casing may cover the build section to prevent keyseating of the formation during deeper drilling. This string is typically cemented to the surface or to the mudline in offshore wells Intermediate Casing.

Intermediate casing is set to isolate unstable hole sections, lost-circulation zones, low-pressure zones, and production zones.

It is often set in the transition zone from normal to abnormal pressure. The casing cement top must isolate any hydrocarbon zones. Some wells require multiple intermediate strings.

Some intermediate strings may also be production strings if a liner is run beneath them. Production casing is used to isolate production zones and contain formation pressures in the event of a tubing leak. It may also be exposed to injection pressures from fracture jobs, downcasing, gas lift, or the injection of inhibitor oil. A good primary cement job is very critical for this string. Liner is a casing string that does not extend back to the wellhead but instead is hung from another casing string.

Liners are used instead of full casing strings to reduce cost, improve hydraulic performance when drilling deeper, allow the use of larger tubing above the liner top, and not represent a tension limitation for a rig. Liners can be either an intermediate or a production string. Liners are typically cemented over their entire length. Tieback string is a casing string that provides additional pressure integrity from the liner top to the wellhead. An intermediate tieback is used to isolate a casing string that cannot withstand possible pressure loads if drilling is continued usually because of excessive wear or higher than anticipated pressures.

Similarly, a production tieback isolates an intermediate string from production loads. Tiebacks can be uncemented or partially cemented.

An example of a typical casing program that illustrates each of the specified casing string types is shown in Fig. Tubing Tubing is the conduit through which oil and gas are brought from the producing formations to the field surface facilities for processing. Properties of Casing and Tubing The American Petroleum Inst. Casing is classified according to five properties: Almost without exception, casing is manufactured of mild 0.

Strength can also be increased with quenching and tempering. API has adopted a casing "grade" designation to define the strength of casing steels. This designation consists of a grade letter followed by a number, which designates the minimum yield strength of the steel in ksi 10 3 psi.

Pipe Strength To design a reliable casing string, it is necessary to know the strength of pipe under different load conditions. Mechanical Properties Each mechanical property of casing and tubing is discussed next. If casing is subjected to internal pressure higher than external, it is said that casing is exposed to burst pressure. Burst pressure conditions occur during well control operations, integrity tests, and squeeze cementing. The burst strength of the pipe body is determined by the internal yield pressure formula found in API Bull.

This equation, commonly known as the Barlow equation, calculates the internal pressure at which the tangential or hoop stress at the inner wall of the pipe reaches the yield strength YS of the material. The factor of 0. The effect of axial loading on the burst strength is discussed later.

If external pressure exceeds internal pressure, the casing is subjected to collapse. Such conditions may exist during cementing operations or well evacuation. The collapse strength criteria, given in API Bull.

This criterion does not represent a "collapse" pressure at all.

Monte Carlo simulation using Excel(R) spreadsheet for predicting reliability of a complex system - IEEE Xplore Document

API Connection Ratings While a number of joint connections are available, the API recognizes three basic types: Coupling Internal Yield Pressure The internal yield pressure is the pressure that initiates yield at the root of the coupling thread.

Round-Thread Casing-Joint Strength The round-thread casing-joint strength is given as the lesser of the fracture strength of the pin and the jump-out strength. Buttress Casing Joint Strength The buttress thread casing joint strength is given as the lesser of the fracture strength of the pipe body the pin and the coupling the box. Extreme-Line Casing-Joint Strength Extreme-line casing-joint strength is calculated as When performing casing design, it is very important to note that the API joint-strength values are a function of the ultimate tensile strength.

This is a different criterion from that used to define the axial strength of the pipe body, which is based on the yield strength. If care is not taken, this approach can lead to a design that inherently does not have the same level of safety for the connections as for the pipe body.

This is not the most prudent practice, particularly in light of the fact that most casing failures occur at connections.

This discrepancy can be countered by using a higher design factor when performing connection axial design with API connections. The joint-strength equations for tubing given in API Bull. If API casing connection joint strengths calculated with the previous formulae are the basis of a design, the designer should use higher axial design factors for the connection analysis.

The logical basis for a higher axial design factor DF is to multiply the pipe body axial design factor by the ratio of the minimum ultimate tensile strength, U pto the minimum yield strength, Y p.

Connection Failures Most casing failures occur at connections. Connection Design Limits The design limits of a connection are not only dependent upon its geometry and material properties but are influenced by surface treatment; phosphating; metal plating copper, tin, or zinc ; bead blasting; thread compound; makeup torque; use of a resilient seal ring many companies do not recommend this practice ; fluid to which connection is exposed mud, clear brine, or gas ; temperature and pressure cycling; and large doglegs e.

Casing and Tubing Buckling Introduction As installed, casing usually hangs straight down in vertical wells or lays on the low side of the hole in deviated wells. Casing Buckling in Oilfield Operations Buckling should be avoided in drilling operations to minimize casing wear. Tubing Buckling in Oilfield Operations Buckling is typically a more critical design issue for production tubing than for casing. Buckling Models and Correlations Buckling occurs if the buckling force, F bis greater than a threshold force, F pknown as the Paslay buckling force.

Loads on Casing and Tubing Strings In order to evaluate a given casing design, a set of loads is necessary. External Pressure Loads Pressure Distributions Pressure distributions are typically used to model the external pressures in cemented intervals. Internal Pressure Loads Pressure Distributions Pressure distributions are typically used to model the internal pressures. Mechanical Loads Changes in Axial Load In tubing and over the free length of the casing above TOC, changes in temperatures and pressures will have the largest effect on the ballooning and temperature load components.

Running in Hole This installation load case represents the maximum axial load that any portion of the casing string experiences when running the casing in the hole. Overpull While Running This installation load case models an incremental axial load applied at the surface while running the pipe in the hole. Green Cement Pressure Test This installation load case models applying surface pressure after bumping the plug during the primary cement job.

Other Load Cases Air Weight of Casing Only. Shock Loads Shock loads can occur if the pipe hits an obstruction or the slips close while the pipe is moving. Service Loads For most wells, installation loads will control axial design. Thermal Loads and Temperature Effects In shallow normal-pressured wells, temperature will typically have a secondary effect on tubular design. Temperature Effects on Tubular Design Annular Fluid Expansion Pressure.

Casing Design To design a casing string, one must know the purpose of the well, the geological cross section, available casing and bit sizes, cementing and drilling practices, rig performance, as well as safety and environmental regulations. Design Objective The engineer responsible for developing the well plan and casing design is faced with a number of tasks that can be briefly characterized. Design strings to minimize well costs over the life of the well.

Provide clear documentation of the design basis to operational personnel at the well site. This will help prevent exceeding the design envelope by application of loads not considered in the original design.

Design Method Phases of Design Process The design process can be divided into two distinct phases. Preliminary Design The purpose of preliminary design is to establish casing and corresponding drill-bit sizes, casing setting depths and, consequently, the number of casing strings.

Mud Program The most important mud program parameter used in casing design is the "mud weight. Hole and Pipe Diameters Hole and casing diameters are based on the requirements discussed next. The production equipment requirements include tubing; subsurface safety valve; submersible pump and gas lift mandrel size; completion requirements e.

Evaluation requirements include logging interpretation and tool diameters. Drilling requirements include a minimum bit diameter for adequate directional control and drilling performance; available downhole equipment; rig specifications; and available BOP equipment.

These requirements normally impact the final hole or casing diameter. Because of this, casing sizes should be determined from the inside outward starting from the bottom of the hole. Usually the design sequence is as described next. Based upon reservoir inflow and tubing intake performance, proper tubing size is selected. Then, the required production casing size is determined considering completion requirements.

Next, the diameter of the drill bit is selected for drilling the production section of the hole considering drilling and cementing stipulations. Next, one must determine the smallest casing through which the drill bit will pass, and the process is repeated. Large cost savings are possible by becoming more aggressive using smaller clearances during this portion of the preliminary design phase. This has been one of the principal motivations in the increased popularity of slimhole drilling.

Typical casing and rock bit sizes are given in Table 7. Detailed Design Load Cases In order to select appropriate weights, grades, and connections during the detailed design phase using sound engineering judgment, design criteria must be established.

Other Considerations After performing a design based on burst, collapse and axial considerations, an initial design is achieved. Sample Design Calculations In the examples that are discussed next, burst, collapse, and uniaxial tension failure criteria are examined. Arctic Well Completions The surface formations in the Arctic, called permafrost, may be frozen to depths in excess of 2, ft.

In addition to addressing concerns about the freezing of water-based fluids and cement, the engineer must also design surface casing for the unique loads generated by the thawing and refreezing of the permafrost.

There are also road and foundation design problems, associated with ice-rich surface permafrost, that are not addressed here. The following is a qualitative description of the loading mechanism in permafrost.

If we consider a block of permafrost before thaw, the overburden and lateral earth pressures surrounding this block are balanced by the intergranular stresses between the soil panicles and the pore pressure in the ice. To maintain equilibrium, the soil compacts, increasing intergranular forces until a new stress state is reached that balances the surrounding earth pressures. The loading of the permafrost is the pore-pressure change caused by the phase change of the pore ice, illustrated in Fig.

Associated with the thaw is a body force or "gravity like" loading caused by the gradient of the pore-pressure change. This loading is equivalent to the loss of the buoyant pressure of the ice on the soil particles. Risk-Based Casing Design Introduction Oilfield tubulars have been traditionally designed using a deterministic working stress design WSD approach, which is based on multipliers called safety factors SFs.

Background In all design procedures, a primary goal is to ensure that the total load effect of the applied loads is lower than the strength of the tubular to withstand that particular load effect, given the uncertainty in the estimate of the load effect, resistance, and their relationship. Working Stress Design WSD is the conventional casing design procedure, as discussed earlier in this chapter, that is, the familiar deterministic approach to the design of oilfield tubulars.

WSD designs to worst-case load, with no regard to the likelihood of occurrence of the load. WSD mostly uses conservative elasticity-based theories and minimum strength in design though this is not a requirement of WSD. WSD gives the engineer no insight into the degree of risk or safety though the engineer assumes that it is acceptably lowthus making it impossible to accurately assess the risk-cost balance. SFs are based on experience and not directly computed from the uncertainties inherent in the load estimate though these uncertainties are implicit in the experience.

WSD sometimes makes the design engineer change loading or accept smaller SFs to fit an acceptable WSD, without giving him the means to evaluate the increased risk. Reliability-Based Design Approaches Both QRA and LRFD are reliability-based approaches. The general principles of reliability-based design are given in ISOInternational Standard for General Principles on Reliability of Structures[5] and a detailed discussion of the underlying theory is given by Kapur and Lamberson.

In addition, a limit-states approach is used rather than elasticity-based criteria. Thus, the "failure criterion" of WSD is replaced by a limit state that represents the true limit of the tubular for a given load effect. Such probabilistic design approaches allow the estimation of a probability of failure of the structure, thus giving better risk-consistent designs.