Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Abstract Casing connections in thermal wells, such as SAGD and CSS wells, experience extreme loads due to exposure to high temperatures up to 200ºC-350ºC, stresses exceeding the elastic limit, and cyclic plastic deformation. To-date, no standard procedure has been adopted by the industry to qualify casing connections for such conditions. In particular, the existing evaluation standard ISO13679/API5C5 exclude temperatures above 180ºC and tubular loads beyond pipe body yield. Proprietary procedures have been used to qualify connections for individual thermal operations, but none of those has been accepted as an industry standard. This paper introduces a new protocol for evaluating casing connections for thermal well applications: Thermal Well Casing Connection Evaluation Protocol (TWCCEP) founded on long-standing work in the thermal-well arena. TWCCEPT has been developed through a multi-client project, sponsored by operators and connection manufacturers involved in thermal-well operations in Canada:EnCana, Husky Energy, Evraz (formerly Ipsco), Nexen, Pengrowth, Petro-Canada, Shell, TenarisHydril, and Total. Recently, International Organization for Standardization (ISO)Technical Committee 67 Sub Committee 5 registered a new work item to consider adopted TWCCEPas an international standard. This paper refers to the TWCCEPT version available at the time of submitting the paper manuscript. TWCCEP employs both analytical and experimental procedures to assess performance of a candidate connection under conditions typical of service in thermally-stimulated wells. The objective of the analytical component is to assess sensitivities of the candidate connection to selected design variables, and identify worst-case combinations of those variables for subsequent configuration of specimens for physical testing. The purpose of the physical testing is to verify performance of the connection specimens under assembly-and-loading conditions simulating the thermal-well service. In addition to the protocol overview, this paper illustrates how engineering analysis, numerical simulation, and reduced-scale physical testing were used in the protocol development to examine impacts of various design and loading variables on connection strength and sealability, and how those results were utilized to formulate the analysis-and-test matrix prescribed in the TWCCEP evaluation procedure. Adoption and consistent use of TWCCEP is expected to increase operational reliability and decrease failure potential of casing strings in thermal wells. Learnings from the protocol development will also help define requirements for connection re-qualification in cases when one or more of the design variables change (i.e., in product line qualification). Thermal well service conditions Loading conditions in extreme-temperature wells, such as Steam Assisted Gravity Drainage (SAGD) and Cyclic Stream Stimulation (CSS), are severe. Maximum operating temperatures in those wells currently reach into the interval between 200ºC and 350ºC. Large temperature variations occur due to production techniques and well interventions, leading to cyclic heating and cooling. When a restrained tubular, such as a cemented casing string, is subject to a large temperature increases during heating, constrained thermal expansion generates mechanical forces in the pipe. Those strain-induced forces are of sufficient magnitude to yield the pipe, even if it is made of a high-grade material. Theoretically, a high-yield pipe material could be chosen to avoid yielding, but typically such choices are not practical due to reduced resistance to environmentalcracking and high cost. In consequence, average stresses in the pipe-connection system exceed the full-pipe-body yield stress, and the system deforms plastically. In addition, strain localization in weaker sections of the pipe-connection system can lead to local plastic strains higher than the average strain, which compounds the degree of the local plastic deformation.
- North America > Canada (0.70)
- North America > United States > Texas (0.28)
- North America > United States > Louisiana (0.28)
- North America > United States > California (0.28)
Summary This paper discusses methods and test procedures for conducting field evaluations to determine the effectiveness of oilfield tubular-inspection equipment and personnel. Specific requirements and equations are proposed for qualifying magnetic particle, ultrasonic, eddy current, radiographic, optical, and mechanical nondestructive test equipment. The design and use of pip standards to check automated pipe-inspection systems are also described. By incorporation of the methods pipe-inspection systems are also described. By incorporation of the methods developed in this paper, nondestructive inspection services can be qualified with respect to the pipe diameter, weight, grade, or critical application of the tubular. Introduction In drilling for oil and gas, we are encountering ever-increasing challenges in the form of more hostile environments. Higher pressures. greater temperatures, corrosive gases, and deeper, deviated wellbores present new problems. Because of these challenges, the quality of problems. Because of these challenges, the quality of tubulars that are used to complete the well becomes even more critical. The oil industry currently ensures the quality of new tubulars placed downhole through nondestructive inspections conducted in the field or at the pipeyard. The inspection equipment typically is designed to locate seams, laps, pill, slugs and thin-wall areas that result from the manufacturing process, as well as mechanical damage from handling. Oilfield tubulars are one of the most important factors that affect the production and safety of any oil or gas well. In particular, tubing and casing are subjected to high tension loads from the weight of the string, burst loads from internal production pressures, collapse loads from external formation pressures, bending loads from wellbore deviations, and other severe conditions, such as sour-gas environments. And finally, these tubulars may remain in production for as long as 20 years with corrosion taking production for as long as 20 years with corrosion taking its toll. The majority of today's oilfield tubulars are made of carbon or alloy steels and are manufactured by the seamless piercing and rolling process. The cost of these tubulars often represents 20 to 40% of the drilling program cost. but the cost of a tubular failure can be even more dramatic. Pipeyard inspection reports for new tubing and casing indicate that about 20% of domestic tubulars are rejected when held to API specifications. Therefore, the pipeyard inspection is critical in maintaining the quality pipeyard inspection is critical in maintaining the quality of the wellbore. Service companies provide tubular inspections for most oil companies. The quality of these inspections varies significantly from region to region. One of the principal reasons for this variation is a lack of specifications for the nondestructive testing (NDT) of oilfield tubulars. Once a specification has been established, the next step is to evaluate and to qualify the inspection company during field evaluations in that region. Existing NDT specifications, such as the American Soc. of Nondestructive Testing (ASNT), the American Soc. for Testing and Materials (ASTM), or API Specifications, are neither detailed enough nor directed specifically enough to the oil field to allow the inspection equipment to be evaluated and qualified to a particular level. The final step in among quality inspections is through adequate supervision and periodic audits of equipment and personnel. periodic audits of equipment and personnel. This paper addresses the specific performance levels for NDT equipment and personnel for oilfield tubular inspections. The requirements developed at Exxon Production Research Co. involve theoretical calculations, review Production Research Co. involve theoretical calculations, review of the existing inspection methodology, and experimental testing in electromagnetics, ultrasonics, and radiography. Then these requirements were incorporated into a procedure for conducting field evaluations to determine and to maintain the quality of oilfield tubular inspections. Field Evaluations of Oilfield Inspection Operations Field evaluations of an oilfield inspection operation consists of testing and documenting information in three principal areas: (1) automated pipe-body inspections, principal areas:automated pipe-body inspections, special end-area and prove-up inspections, and personnel certification and reference documents. These areas are discussed individually and described in more detail to pert-nit field evaluations to be conducted. Performance specifications that serve as a basis for evaluating the quality of the inspections are described. When field evaluations are made, all pertinent information that describes the inspection equipment, personnel, and procedures should be recorded. Identification numbers should be assigned to the inspection equipment when no other identifiable markings exist to allow easy identification at a later date. This also serves as a list that describes the equipment available at the particular inspection site. Automated Pipe-Body Inspections The geometrically uniform section of the pipe (all but the last few feet from either end) typically is inspected by an automated inspection system capable of scanning pipe at about 1 ft/sec [0.3 m/s]. JPT p. 88
- North America > United States (0.46)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Abstract It has long been recognised that during and after drilling through certain formations, the rock moves inward and begins to close off the well. Normally this phenomenon is considered undesirable since it can cause problems for drilling and casing running. It can however be put to good use as the mechanism to create an annular barrier behind casing. In order to extend the life of a number of North Sea brown fields many well slots on production platforms and sub-sea templates are being re-used. This process involves permanent plug and abandonment of the old well track prior to sidetrack drilling into a fresh area of the reservoir. Norwegian Continental Shelf (NCS) regulatory requirements dictate that compliant procedures for well abandonment require the establishment of double barriers to avoid leakage from the reservoir. With a shortage of sufficient traditional cement barriers these wells often need costly remedial work in order to meet abandonment requirements. Traditional sonic and ultrasonic azimuthal bond logging provides information on the material immediately behind the casing. Many such bond logs show solid material behind the casing far above the theoretical cement top. Clear correlation of this bonding pattern to shales, known to cause problems during drilling, indicates that the shale has sealed off the annular region and that it is the presence of such formation material that results in a good bond log response Logging and pressure testing sealed off zones in a number of wells allowed the bond log response to be qualified for a certain formation without further pressure testing. In this manner logs can provide a clear answer of whether shale successfully seals off certain zones and consequently provides a natural annular barrier. This technique has been employed successfully on over 40 wells, proving non-destructively that high quality natural annular barriers had formed, resulting in elimination of complex remedial work and substantial cost savings. Introduction Historically log responses indicating a good bond have often been observed on bond logs far above the theoretical top of cement. Many explanations exist for these responses and it is likely that there are a number of possible causes. The most frequent cause is believed to be formation displacement. This is supported by the following observations on the log:Good bond log response far above the top of the theoretical cement. Good quality bond correlates with shale rich intervals. Large and sometimes frequent changes in bond log response at the same depth as geological changes. Above the casing shoe of an outer casing string the log response changes from good quality bond to free pipe as the formation can no longer impinge onto the inner casing string. Sinusoidal patterns on ultrasonic bond log images imply geological beds impinging on the outside of the casing.
- Europe > Norway (1.00)
- Europe > United Kingdom > North Sea (0.54)
Abstract The design of completions which are effective and reliable is of increasing significance to the viability of both existing and new fields. With greater emphasis being placed on the input of advanced engineering techniques to oilfield developments, the improvement of the completion design process is an important area for investigation. This paper presents results, based on information supplied by North Sea operators, of an attempt to rationalize how design decisions are reached and what factors influence the selection or specification of completion equipment and completion procedures. The paper discusses the process of constructing design logic flow charts with the completion knowledge acquired in the study. Introduction Well completion practices are an important facet of any oil and gas development providing, as they do, a link between the initial drilling of the wells and their subsequent production. Petroleum Engineering, as a whole, has seen remarkable Petroleum Engineering, as a whole, has seen remarkable technological advances over recent years due to greater treatment analysis being applied and to the advances in analytical tools available e.g. access to micro computers. These developments have been fuelled by the need to develop offshore petroleum reserves in areas such as the North Sea. The completion of a drilled well may not represent the major component of the total cost of a development well, but the importance of effective completions have been fully realised given the experience of the operators in the North Sea. The substantially increased cost of all activities conducted in an offshore environment as hostile as the North Sea extends to the cost of completion but more importantly to the financial consequences of ineffective completion practices. An effective well completion should allow production from or injection into the reservoir and satisfy the following criteria:Optimum production/injection performance Safety - the provision of the means to effect cessation of production and the ability to restore control of the well to the operator under both controlled and emergency conditions. Integrity and reliability - to allow extended production with limited intervention Minimise costs - the costs associated with the well comprise:The initial completion costs All production costs All remedial or stimulation costs In most cases the completion of the well has focused on the design of the completion string and the selection of tubing components. However, if a well completion is to meet the above objectives, the completion design must optimise all aspects of the completion. Completion activities have frequently been reported for specific fields. However, little has been published which attempts to either rationalise completion design or to compare completion strategies on more than a specific field basis. Patton and Abbot attempted to rationalise completion Patton and Abbot attempted to rationalise completion design by constructing simple flow diagrams to illustrate data requirements and possible decision models and criteria. p. 347
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > North Sea (1.00)
- (2 more...)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
ABSTRACT This paper describes an integrated approach to fracture control problems - applied first as a necessary adjunct to the authors' own engineering practice, then in developing the US National Codes for tubular structures, AWS D1.1 and API RP 2A, as well as related standards for materials, welding, and testing. INTRODUCTION A well engineered structure requires that a number of factors be in reasonable balance. Factors to be considered in relation to economics and risk in the design and steel selection for tubular connections include:static strength, fatigue resistance fracture toughness, homogeneity and resistance to lamellar tearing, and weld ability. Many of these same factors arise again in setting up QC/QA programs during construction, including such issues as weld profile control and allowable flaw size to be applied during nondestructive testing. Human factors and organizational issues must also be addressed, such as personnel qualifications and lines of communication/approval. CONVENTIONAL FRACTURE CONTROL Most fracture control problems in offshore platforms occur in the tubular connections, or nodes. Use of the "hot spot" stress, as would be measured by a perpendicular strain gage adjacent to the toe of the weld in the region of localized plastic deformation, serves to bring fatigue and fracture problem for many different node geometries into a common focus (refs. 1, 2). Use of elastic hot spot stress as an Indicator of ultimate strength is only approximate. Local yielding, mobilization of plastic section modulus, trail stresses, and load redistribution via plastic deformation occur as tubular connections reach their practical ultimate capacity. These phenomena, which occur in the presence of weld-toe notches, place severe demands on the materials being used, particularly in the chord or main member of a tubular connection. Although elastic-plastic analysis methods are now becoming more widely available, design practice typically uses well-calibrated empirical formulas for ultimate strength (e.g., punching shear in AWS D1.1). Once the designer has taken care of the most fundamental requirement -- strength -- then it is time to consider such problems as fatigue and brittle fracture. Design for fatigue routinely uses the hot spot approach, with parametric stress concentration factors (SCF, e.g. ref. 3), and allowable hot spot stresses derived from prior generic fatigue analyses. EXHIBIT 1 shows the original American fatigue design curve based on hot spot stress, which was used to derive allowable one-in-a-lifetime allowable hot spot stress range of 80-ksi for structures exposed to a typical Gulf of Mexico wave climate. Lower allowable are used in more severe environments (ref. 4, 6). Gulf of Mexico lowest anticipated service temperatures are 14 degrees-F air, 40-60 degrees-F water. Typical steel for "joint cans" (heavy wall chord section) is API Spec 2H, which calls for drop-weight nil-ductility transition at minus 40 degrees (ref. 6) .- class A fracture toughness.
- Energy > Oil & Gas > Upstream (1.00)
- Health & Medicine (0.88)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Well Completion > Hydraulic Fracturing (1.00)