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Abstract Over the years, cement packers have been used to provide zonal isolation above the production packer without pulling the completion. Experience has shown that the risks associated with placement of the packers is fairly high and leaks are difficult to repair. A number of ways to place cement packers have been developed over the years and a new method has been recently field trial tested in the Gulf of Mexico in the SMI 288 field. This paper introduces a novel approach developed to install a completion, in a through-tubing process, to recover otherwise uneconomical, behind pipe reserves that are above existing production packer installations. The entire process takes advantage of significantly improved mature technologies. The application of this process can increase recoverable reserves and avoid expensive workover costs when the reserve estimates are questionable. This paper will discuss the methodology used and the results of a case history included to illustrate the implementation of the process. It involved creating a window in the tubing across the new zone and placement of a cement packer above the window. The window was created so as to lower the completion drawdown and lower the risk of completing in wells requiring sand control. Introduction Recompletions offshore in the Gulf of Mexico are sometimes not performed due to the cost of rig mobilization, risk and reserve base remaining in the wellbore Cement packers placed above an existing production packer offer a rigless means of casing isolation and allow production from marginally economical up hole selective candidates. The concept of placing a cement packer in the tubing-casing annulus is not new. There are many variations in how this has been accomplished utilizing varying methods and different types of equipment. In the past, the success rate of placing cement packers that isolate has not been very high. Small micro channels, which develope for various reasons do not result in a complete hydraulic seal of the annular area. This restricts annular flow, but does not completely seal it off. Such leaks result in casing pressure that is difficult to remedy since injection rates/pressures are usually insufficient/too high to perform a cement squeeze repair. An effort was made to develop a better, more reliable way to place cement packers and successfully test them. A Cement Packer Team was commissioned within Chevron in the fall of 1993. Past processes were reviewed, noting the deficiencies. The session resulted in an outline of ideas and issues that must be addressed in order to increase the reliability of the cement placement process. Additionally, at this point it was noted that a method of removing a section of tubing without having to mobilize a rig would result in better perforating performance and would also facilitate placement of a through tubing sand control means (ie, through tubing gravel pack, resin consolidation, fracture with proppant flowback additive, etc). Creation of the window in the tubing string was considered important in lowering the risk of an unsuccessful completion. It became apparent that a casing access window (CAW) completion procedure could be used with good candidate wells and that there are some wells that would require less sophisticated (and less expensive) techniques in the overall procedure. P. 623
This can create length and force changes in the tubing string that can potentially affect thepacker and downhole tools. After the packer is installed and the tubing landed, any operational mode change will cause a change in length or force in the tubing string. The resultant impact on the packer and tubing string is dependent on: * How the tubing is connected to the packer * The type of packer * How the packer is set * Tubing compression or tension left on the packer. The length and force changes can be considerable and can cause tremendous stresses on the tubing string, as well as on the packer under certain conditions. The net result could reduce the effectiveness of the downhole tools and/or damage the tubing, casing, or even the formations open to the well.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Although a packer is conceptually simple and has been used for a long time, its associated force calculation can be confusing and sometimes complex. This is because the force calculation involves tubing axial load, piston effect, tubing-to-packer force, and packer-to-casing force, where a pressure discontinuity and axial load discontinuity over the packer is common for its functionality in a well. This work revisits and clarifies the packer force calculation with a systematic method. A free body diagram analysis is used to comprehensively consider the piston effect from the fluid pressure difference from above and below the packer, the tubing axial force from above and below packer, the weight of the packer, the packer to casing force, and packer to tubing force, in which the buckling effect and temperature effect are considered in the axial force component. A general formula is given to explain and calculate the tubing-to-packer force and packer-to-casing force; this formula is universal and applicable for various packer and tubing configurations. A physical and mathematical treatise and discussion of the theoretical basis of related force calculation with a packer is provided to clarify confusion points commonly encountered. A set of case studies is included to demonstrate the packer force calculation using the general formula with different packer and tubing configuration conditions. Through these case studies, the formula is shown to be a general form formula, which is universally applicable for various packer and tubing configuration conditions. Simple guidelines are presented with examples in these case study calculations to help explain and clarify the force calculation steps in a straightforward manner to eliminate the confusion encountered when performing force calculations with a packer in a well design. This paper provides a general formula in a straightforward manner to explain and clarify the force calculation for packers. This method is useful to engineers who perform packer selection, well planning, and detailed well design, and provides fast verification.
- Asia (0.68)
- North America > United States > Texas (0.28)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Well Completion > Completion Installation and Operations (1.00)
Introduction The successful use of oil well packers requires, in part, an understanding ofthe pressures which exist at the packer in various applications and anunderstanding of the characteristics of the various types of packers. It iswith these pressures, the resultant forces, and the characteristics of packers, that this paper is primarilyconcerned. An oil well packer may be defined as a mechanical device for blocking thepassage of fluids in an annular space. In the more usual case, the annularspace is that between the tubing or drill pipe in a well and the casing, andpackers which block such an annular space are broadly referred to as casingpackers. In the other case, the annular space is that between the tubing ordrill pipe and the walls of an open hole, and packers for blocking this spaceare generally called formation packers. While the hydraulics involved areessentially the same for casing and formation packers, a greater variety of conditions areencountered in the use of casing packers and only casing packers will bediscussed. After a packer has been set and a pressure seal effected between tubing andcasing, the packer is comparable to a piston in a cylinder. Pressures actingupon a piston result in forces which will move the piston unless some means isprovided to prevent such movement. In the same manner, pressures acting upon a packer will move the packer unlessthere is present a sufficiently great restraining force. Packer Classifications Packers may be classified according to the pressure conditions under which theyare capable of blocking the annular space between tubing and casing. Fig. 1shows schematically two types of packers in common use. These packers arecapable of blocking the annular space against the passage of fluids under adifferential pressure of significant magnitude only when the pressure in theannular space above the packing element is greater than the pressure below. Itmay be seen that in Fig. 1-a, slips with teeth which bite into the casing andprevent downward movement are provided. In Fig. 1-b, an anchor preventsdownward movement. In each case, there is only the tubing to prevent upwardmovement when differential pressures act to move the packers upwardly. Packerswhich hold only a significant differential pressure acting downwardly have beenin use since the early days of the oil industry and will hereafter be referredto as conventional type packers. T.P. 2710
ABSTRACT Permanent production packer installations have been widely used in Canadiangas wells. They also have been used, but to a lesser degree, in oil and waterwells. A permanent production packer virtually becomes a part of the casing andprovides a sound, reliable base on which a successful well completion may bebuilt. Although many types of installations have been used successfully, thispaper will describe only those most commonly used. As tubing movement must be amajor consideration in the design of permanent packer installations, this paperwill also discuss causes, effects and calculations for such movement. INTRODUCTION PERMANENT TYPE PRODUCTION PACKERS have proved to be efficient and reliabletools for segregating fluids and pressures in Canadian gas wells. Most suchinstallations have been in wells that are particularly hot, high pressure orcorrosive, and in wells where more than one of these extreme conditionsexist. Due in part to this variety of conditions -along with fluid, pressure andtemperature changes encountered during well treatment, and well owners'individual preferences -several different basic packer installations haveevolved. As most of these installations have proved highly successful, it appearsuseful to describe in detail those most commonly used. To this end, differentpermanent packers and allied equipment will be shown and discussed. This will be followed by diagrams and explanations of the nine most commonbasic installations. As a major consideration in almost all of these gasinstallations has been tubing movement, the causes, effects and calculationsfor same will be described. For the most part, all discussion will be confinedto installations in wells with a single gas zone. With the exception ofreference to hot oil and fluid injection strings, discussion will center onwells with single tubing strings. PERMANENT PACKERS AND ALLIED EQUIPMENT Permanent production packers may be set on either wire line or tubing. Ontubing, this may be achieved by mechanical or hydraulic means. Most packers areset on wire line for greater accuracy and speed and to minimize the possibilityof accidental presetting. Such packers fall into two categories top sealing andthrough sealing. Top Sealing packers provide a larger minimum bore (I.D.) forproduction or injection (Figure 1a). Through Sealing packers allow for the addition of tailpipe to theseals on the tubing string. Also, on some through sealing installations, additional seal units maybe attached and the tubing allowed to travel. Thisminimizes or eliminates the possibility of parting at the surface (Figure1b). Also available are permanent production packers with packer body extensionson the bottom, on which maybe be installed tailpipe or other equipment, or withpacker bore extensions on the bottom which provide additional sealing borelength and external protection to the seals from corrosive well fluids (Figures2a and 2b.