Read Microsoft Word - Website - Casing & Tubing Revisions 9-9-03.doc text version

Casing and Tubing Design and Analysis Treybig Enterprises, Inc.

303-740-8542

[email protected] Treybig Enterprises combines its engineering expertise and field data with sophisticated casing and tubing analysis software to: · · · provide accurate and economical casing and tubing designs to fit any well plan, establish safe load limits for existing strings, and determine the probable cause for failures in existing strings of casing or tubing.

Expertise with Sophisticated Software Programs Treybig Enterprises expertly employs computer software programs to develop safe, but economical, designs for new casing and tubing strings. These programs can also help determine, through a comprehensive loading analysis, what loads can be safely applied to existing strings. In addition, they can be used to determine the most probable cause of failures in existing strings. Over the past eighteen years that Treybig Enterprises has designed and analyzed oilfield tubular strings, the overwhelming reason for casing and tubing failures has been due to either inadequate initial design or the absence of proper load analysis during the life of the string. Designs and load analyses based on oversimplified well conditions and published pipe strengths cause the majority of failures, with the possible exception of cases involving shallow, low-pressure wells. Predicting Casing and Tubing Stresses Stresses generated in casing and tubing strings due to imposed loads are triaxial, rather than biaxial or uniaxial. The collapse resistance, internal yield (burst) pressure and tensile strengths published by the API refer only to simple, uniaxial, loading, i.e., tensile strength in absence of pressure and burst and collapse strengths in the absence of axial loads. Treybig's primary software program uses the Hencky-von Mieses theory to describe the strength of a steel tube. This theory is the most widely accepted criterion for describing the yielding of ductile materials and is the most popular means of relating loads and stresses in oil field tubular products. The Hencky-von Mieses theory considers the simultaneous application of axial and lateral loads on the string through an evaluation of the three principal stresses in a cylinder, i.e., axial, radial and tangential (hoop) stresses. By using this theory, a better examination of the effects of actual well conditions can be obtained, rather than merely using a simple one-direction load analysis. Realistic Models The model produced by this program can closely simulate the actual conditions that any given string of casing or tubing will be subjected to over its life. It is the most realistic model available for calculating the forces and stresses that exist in a string of casing or tubing. The program can be used to produce a comprehensive analysis of the applied

Treybig Enterprises, Inc. loads on a particular string, or it can be used to produce a tubular design optimized by cost and user specified design conditions. Developing Economical Designs Treybig can use the design and analysis software to model any combination of pipe sizes, weights, grades and connection types that are in an existing string. A priced database of tubular products, including all API casing and tubing and all of the most popular non-API products, is included in the program. The program uses this database to select the most economical pipe in a design. Prices for each pipe in the database can be input to reflect actual, up-to-date costs. In addition to the pipes in the program's database, the program has the ability to calculate the performance properties of any size, weight and grade of new pipe that is not included in the standard database, as well as the performance properties of used pipe where the dimensions and grade are known. These calculations use the API formulas contained in API Bulletin 5C3. The program will allow the user to override the pipe properties contained in the database and specify other material properties (yield and tensile strengths, wall thickness, outside diameter, etc.) or performance property for any pipe in the string. Another very useful option of this program is the ability to limit the pipe used in the design to only those items that are currently in inventory. Using this feature, the most economical design can be developed with materials that are known to be available. Planning for Corrosives There may be times when it is necessary to use special corrosion resistant alloys (CRA) in the casing or tubing strings, because of the corrosive nature of the produced products. In some environments, if a function of the flow stream's velocity and density is below some critical value, it may be possible to safely avoid the use of CRA materials. Separate sets of computer programs (described below) have been developed where this critical velocity/density value can be calculated for different flow stream mixtures. If CRA materials are indeed necessary, allowances must be made for the differences between the mechanical properties of these special alloys and those for steel. The design/analysis program allows the user to input different values of Young's Modulus, Poisson's Ratio, coefficient of thermal expansion and material density. If values for these properties are not entered, the program defaults to the values for steel. Flexible Models The models produced by this program are highly flexible and are capable of describing practically any loading condition. Casing and tubing strings must be designed to withstand multiple loading conditions, including initial running, cementing, landing loads, high differential burst and collapse pressure loads and significant changes in temperature over the life of the string. In addition to the initial base case, up to nine load cases can be modeled to evaluate a single string design. All designs and load evaluations begin with a case describing the external and internal pressure and temperature profiles imposed along the length of the string at the time it is installed in the well. For casing strings, the initial case is the cemented condition after the hanging load is placed in the wellhead slips. For a string of tubing, the initial case is

2

Treybig Enterprises, Inc. the landed condition for the string. The program includes a provision for changing the axial load by picking up or slacking off the string. This ability to change the axial load is necessary to correctly model slackoff on casing tieback receptacles and production tubing strings, or to impose "overpull" on a string to preclude helical buckling. Another procedure performed by the design and load analysis program is an evaluation of possible helical buckling conditions in the string. The entire uncemented portion of a casing string or the total length of a tubing string is checked for helical buckling in both the base case and each individual load case. If buckling is predicted, changes in loading conditions to preclude buckling can be evaluated using additional models. Calculating Temperature and Pressure Each load case that is placed on a string generates a unique pressure and temperature profile. Changes in the temperature profiles produce changes in the string's axial stress. Changes in the internal and external pressure profiles not only produce changes in the radial and hoop stresses, but also change the axial stress due to Poisson's effect. For rigorous designs or load analyses, it is necessary to have reasonably accurate estimates of the various temperatures and pressures that affect the stresses in the string. To provide this important input information, Treybig Enterprises has developed a series of computer programs designed to calculate the temperatures and pressures that might exist in any given situation. A description of each of these programs is included below. Computer programs that predict temperature profiles of casing and tubing strings are: · CIRCULATING FLUID TEMPERATURES: The initial temperature of a string of casing or tubing is related to the circulating fluid temperature history of the wellbore. A computer program has been developed that will calculate the temperature of a circulating fluid at multiple points in the wellbore as a function of time. This program considers the effects of: (1) the well geometry (i.e. all previous casing strings, open hole sections and annular fluids), (2) the length of the final circulating period, (3) the circulating rate, (4) the circulating fluid properties, (5) the geothermal gradient, (6) the inclination angle of the wellbore and (7) the dynamics of the inner pipe string. The output generated by this program is the fluid temperatures, inside and outside of the casing or tubing, at the end of the final circulating period. · STATIC FLUID TEMPERATURES: Once circulation has stopped, the temperature of the static fluid moves toward equilibrium with the static earth temperatures. A computer program has been developed that will calculate the temperature of the static fluid, at multiple points in the wellbore, as a function of time after circulation has stopped. This program considers the effects of: (1) the well geometry (i.e. all previous casing strings, open hole sections and annular fluids), (2) the length of the final circulating period, (3) the circulating rate, (4) the circulating fluid properties, (5) the geothermal gradient, (6) the inclination angle of the wellbore, (7) the length of each circulating period below the depth of interest and (8) the length of each static period below the depth of interest. The output generated by this program is the static temperature of the fluid, inside and

3

Treybig Enterprises, Inc. outside of the casing or tubing, at selected time intervals after the final circulating period. Static temperatures can be estimated for up to forty-five separate depths. · FLUID INJECTION TEMPERATURES: This program will calculate the temperature of a fluid injected into either the casing or the tubing at the surface, at multiple points in the wellbore, as a function of time, after initiation of injection. This program considers the effects of: (1) the well geometry (i.e. all previous casing strings, open hole sections and annular fluids), (2) the injection time, (3) the injection rate, (4) the properties of the injected fluid, including amount and type of proppant, (5) the geothermal gradient, (6) the inclination angle of the wellbore and (7) the temperature of the injected fluid prior to injection. The output generated by this program is the temperature of the fluid, inside of the casing or tubing, at selected depths at the end of the injection period. · FLOWING WELL TEMPERATURES: This program will calculate the temperature of a flowing well stream comprised of various percentages of gas, oil (condensate) and water. The flow path can be through the casing, the tubing or the annulus between the tubing and the casing. Temperatures are calculated at multiple points in the wellbore, as a function of time, after initiation of flow. This program considers the effects of: (1) the well geometry (i.e. all previous casing strings, open hole sections and annular fluids), (2) the length of the flow period, (3) the flow rate, (4) the physical properties of the gas, oil and water, (5) the geothermal gradient, (6) the inclination angle of the wellbore, (7) the Joule-Thompson effect for expanding gas and (8) the relative amounts of gas, oil and water in the flow stream. The output generated by this program is the temperature of the flowing fluids, inside of the casing or tubing, at selected depths at the end of the flow period. · AIR DRILLING TEMPERATURES: This program will calculate the temperature of the fluids in the annulus between the drill string and the casing/open hole, while drilling with either air or air mist (foam). Temperatures are calculated at multiple points in the wellbore, as a function of time, while drilling after an extended downtime (bit trip, etc.). This program considers the effects of: (1) the well geometry (i.e. all previous casing strings, open hole sections and annular fluids), (2) the length of the drilling (circulating) period, (3) the air and water injection rates, (4) the physical properties of the air and water, (5) the geothermal gradient, (6) the inclination angle of the wellbore, (7) the Joule-Thompson effect for expanding air and (8) any back pressure on the annulus at the surface. The output generated by this program is the temperature of the annular fluid at the end of the drilling period at selected depths. Computer programs that predict pressure profiles of casing and tubing strings are: · CIRCULATING PRESSURES: This program will calculate the pressures at multiple depth points in the well, while circulating a fluid through either the casing or the tubing string. It considers the effects of: (1) the inside and outside dimensions of the inner pipe string, (2) the inside diameter of the outer pipe/borehole wall, (3) the circulating rate, (4) the circulating fluid properties, (5) the effect of temperature on the fluid properties, (6) the circulating temperatures at selected depths in the well and (7) the inclination angle of the wellbore. The output 4

Treybig Enterprises, Inc. generated by this program is the surface pumping pressure and the friction pressure loss inside the string.

· FLUID INJECTION PRESSURES: This program will calculate the pressures at multiple

depth points in the well, while injecting a fluid through either the casing or tubing string. It considers the effects of: (1) the inside dimensions of the inner pipe strings, (2) the number and diameter of the perforations, (3) the fluid injection rate, (4) the properties of the injected fluid, including amount and type of proppant, (5) the effect of temperature on the fluid properties, (6) the injection fluid temperatures at selected depths in the well, (7) the inclination angle of the wellbore and (8) the fracture propagation pressure of the formation. The output generated by this program is the surface pumping pressure and the friction pressure loss inside the string.

· FLOWING WELL PRESSURES: Depending on the relative amounts of produced oil,

gas and water in the flow stream, one of three available programs can be used to calculate the flowing pressures in a pipe string. One program is designed for relatively dry gas. Another program is designed for high gas/oil ratio (GOR), gas condensate wells with some associated water production, and the third is for low GOR oil wells with some water production. Each program will calculate the flowing pressures of a well stream comprised of various percentages of gas, oil (condensate) and water. The flow path can be through the casing, the tubing or the annulus between the tubing and the casing. Pressures are calculated at multiple depth points in the wellbore. These programs consider the effects of: (1) the inside dimensions of the inner pipe strings, (2) the mechanical condition of the pipe wall, (3) the flow rate, (3) the physical properties of the gas, oil and water, (5) the operating pressures and temperatures of the surface separation equipment, (6) the geothermal gradient, (7) the flow stream temperatures at selected depths in the well, (8) the inclination angle of the wellbore and (9) the relative amounts of gas, oil and water recovered at the surface. Where PVT data are available for the produced fluids, the data can be used to model the effects of changes in pressure and temperature on the composition of the flow stream under downhole conditions. The output generated by this program is dependent on the data desired. If the flowing (shut-in) surface pressure is known, the program will calculate the flowing (shut-in) bottom hole pressure. If the desired output is the flowing (static) surface pressure, the program will first calculate the flowing bottom hole pressure based on input of the well's assumed absolute-open-flowpotential, gas flow equation exponent and static reservoir pressure. The program will then calculate the flowing surface pressure. The friction pressure loss inside the string is also calculated.

Computer programs that predict the need for CRA material tubulars: · FOR BLACK OIL AND VOLATILE OIL RESERVOIR FLUIDS: This program will calculate the flow stream velocities at various depths in the casing or tubing and compare those velocities with the critical velocities for both CO2 and H2S gas that will dictate the need for corrosion resistant alloy (CRA) material. It considers the 5

Treybig Enterprises, Inc. effects of: (1) the inside diameter of the tubing or casing, (2) the reservoir pressure and temperature, (3) the bubble point pressure, (4) the solution GOR at the bubble point, (5) the API gravity of the stock tank oil, (6) the gravity of the gas at the separator, (7) the mole fractions of the acid gases, (8) the separator's operating pressure and temperature, (9) the oil producing rate, (10) the separator GOR and (11) the flowing pressure and temperature at the selected depths in the well. The output generated by this program compares the actual flow stream velocity to the critical stream velocities that will allow conventional alloy steel to be used in the string. These critical stream velocities are the highest stream velocities that will not erode the protective corrosion scale from the pipe wall.

· FOR RETROGRADE CONDENSATE RESERVOIR FLUIDS: This program will calculate

the flow stream velocities at various depths in the casing or tubing and compare those velocities with the critical velocities for both CO2 and H2S gas that will dictate the need for CRA material. It considers the effects of: (1) the inside diameter of the tubing or casing, (2) the reservoir pressure and temperature, (3) the amount of condensate and water produced downstream of the separator, (4) the gas rate, (5) the flowing pressure and temperature for selected depths in the well, (6) the specific gravity of the gas at those depths, (7) the specific gravity of the condensate at those depths and (8) the percentage of the well stream that is liquid at those depths. To accurately model a retrograde fluid, it is necessary to have PVT data of the gas and condensate mixture. The output generated by this program compares the actual flow stream velocity to the minimum stream velocities that will allow conventional alloy steel to be used in the string. The flow stream densities at the selected depths are also given.

· FOR WET AND DRY GAS RESERVOIR FLUIDS: This program will calculate the flow

stream velocities at various depths in the casing or tubing and compare those velocities with the critical velocities for both CO2 and H2S gas that will dictate the need for CRA material. It considers the effects of: (1) the inside diameter of the tubing or casing, (2) the specific gravity of the gas, (3) the critical temperature and pressure of the gas, (4) the API gravity of the condensate, (5) the amounts of condensate and water produced downstream of the separator, (6) the gas rate and (7) the flowing pressure and temperature at selected depths in the well. The output generated by this program compares the actual flow stream velocity to the minimum stream velocities that will allow conventional alloy steel to be used in the string. The flow stream densities at the selected depths are also given. For more information regarding possible applications of the above programs, please contact Jerry Treybig, President of Treybig Enterprises, Inc., by telephone at either 303-740-8542 or 303-910-0565 or by email at [email protected]

6

Information

Microsoft Word - Website - Casing & Tubing Revisions 9-9-03.doc

6 pages

Report File (DMCA)

Our content is added by our users. We aim to remove reported files within 1 working day. Please use this link to notify us:

Report this file as copyright or inappropriate

464821


Notice: fwrite(): send of 197 bytes failed with errno=104 Connection reset by peer in /home/readbag.com/web/sphinxapi.php on line 531