Improving liner cementing has been a constant objective of the industry. Recent developments in rotating liner hanger technology have made this cetnenting technique applicable to more wells than before.Presented here is an analysis of 45 jobs done during i '/2 years. The study examined mechanical success ratios as a function of liner size, depth, length, method of rotation, setting tool types, deviation, casing hardware ! (centralizers, scratchers, etc.), and bearing load. The results give the drilling and completion engineer a better understanding of the chances of a mechanically successful job.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 46th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in New Orleans, La., Oct. 3–6, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract This paper describes a new core barrel device for cutting and retrieving subterranean cores, particularly from soft or unconsolidated formations; it utilizes a fluid-pressure collapsible sleeve above the core bit to receive and hold the cored material and permit its retrieval in its original subterranean condition. Pressure responsive valves maintain a fluid pressure behind the collapsible sleeve to retain it in the collapsed position until the core is received in the sleeve and also permit fluid behind the sleeve to exhaust as the core enters the sleeve while the sleeve continues to offer lateral support for the core and also remains collapsed above the core. When the core barrel is withdrawn, a small amount of soft core material may fall from the lower portion of the core barrel and the lower portion of the sleeve collapses to retain the remainder of the core in the core barrel. This paper describes the operation of the new core barrel and full results obtained in very soft uranium ores in South Texas. Some of these cores were previously unobtainable by former conventional methods. The operation of this tool is quite simple and it can be furnished in small or larger sizes and in varying lengths, permitting its use in areas and fields offshore or land, small or large rigs, shallow or deep, and can be used for the recovery of mineral ores or petroleum sands. Drawings illustrating its potential use in ocean floor sampling are shown. Introduction The recovery of soft unconsolidated formation core samples has always been a difficult problem. In the past, conventional coring equipment has been modified by the use of "finger" catchers, traps and other devices to facilitate recovery of such formations. However, there is a need for a simple tool that will not only retain the core when it is retrieved but will support it and prevent its bridging as it is being cored. This new tool should be simple to operate and should be available in different lengths and sizes. It should be adaptable to large and small drilling rigs and operate successfully at any depth on land or water.
For several years, the author has participated in the design and installation of equipment for many deep Anadarko Basin wells, including the two deepest wells ever drilled. Most of the early Anadarko deep completions featured large OD production tubing, anticipating high productive well capacities; but more recent completions have been made with smaller 2 7/8" OD tubing, and the problems of tubing stress are quite serious. For instance, well shut-in pressures may reach to over 12000 psi. Fracturing with proppant may require surface tubing pressures of over 17000 psi. These types of problems will be discussed and successful solutions for them are illustrated. High pressure casing and tubular prices, and recent shortages of some tubulars, have demanded new approaches to casing and liner design programs. One problem, not unfamiliar to earlier deep drilling problem, not unfamiliar to earlier deep drilling engineers, is the problem of high pressure liner leaks. The use of "liner-top" packers installed after the liner has been cemented, to control this leakage, will be discussed and illustrated. The new methods of equipping these wells will be discussed here for the first time and several installations will be illustrated. Some recent dual completions of high pressure Anadarko wells will be discussed and illustrated. Introduction Several years ago, it was common to design deep well completions in the Anadarko Basin with large tubulars, such as 3 1/2 in. OD and 4 1/2 in. OD tubing, for production. Some operators still do this in larger, more productive reservoirs; but most now use 2 7/8 in. OD tubing. When smaller 2 7/8 in. OD tubing is used, combined tubing fiber stress during high pressure operations may be excessive, unless special pressure operations may be excessive, unless special precautions are taken. The tubing shut-in pressures in precautions are taken. The tubing shut-in pressures in some wells exceed 14000 psi. Fracturing pressures have exceeded 17000 psi. Tools must be used which will withstand these pressures and, at the same time, enable the tubing to shorten during treatment without permanent deformation. A way should be provided for permanent deformation. A way should be provided for removal of the tubing, in case of tubing failure, without having to mud up and kill a producing well. Gas leakage around the tops of liners set through Morrow/Springer formations are common and the liner tops must be sealed to prevent excessive pressuring of the annulus. Liner top packers, which have seal nipples landed into the liner tie-back receptacle and a pack-off seal setting in the intermediate casing, have pack-off seal setting in the intermediate casing, have been used for this purpose, if the leak cannot be squeezed off. DISCUSSION OF HIGH PRESSURE INTERVALS IN ANADARKO BASIN Fig. 1 shows how pore pressure and frac gradients vary with depth in a typical Anadarko Basin well. High pressure above-normal gradients begin at approximately 9500 ft., in the Tonkawa formation, and increase with depth to the top of the Morrow sand at approximately 17000 ft. When low permeabilities are found in the suspense interval from 12400 ft. to the top of the Morrow sand, most operators set intermediate casing in the Morrow shale above the Morrow sand. If permeability is present, intermediate casing is set in the Deese shale present, intermediate casing is set in the Deese shale around 12000 ft. and a drilling liner is set in the Morrow shale around 15800 ft. The frac gradient often is very close to the pore pressure gradient as the depth of the well approaches pressure gradient as the depth of the well approaches the top of the Morrow sand. When the frac gradient in the primary objective zones is equal to or very close to the pore pressure gradient, a second drilling liner is required to penetrate and complete in the lowermost part of the Morrow/Springer column, usually about part of the Morrow/Springer column, usually about 21000–22000 ft. The deeper horizons below the Morrow/Springer are not generally considered to be abnormally pressured. There are some high pressure anomalies in the Woodford shale and the Simpson group, however; but the length of this paper does not permit proper discussion of completions below the Springer.
In the past 5 years more than 80 01 the deepest wells in the world have been drilled below 20,000 It in the J)elaware basin 01 West Texas. Most 01 these wells have heen tremendous gas producers and have required some extraordinary completion procedures. The main lac tors causing completion problems are depth, pressure, temperature, high producing rates, and extensive stimulation treatments. Pronounced changes in tubing length (as much as 22 It within a few hours) are caused by temperature and pressure fluctuations that occur between treating and flowing. Presented are equations to calculate elongation and shortening, and a graph to calculate expansion. Described and discussed are a widely used typical completion as well as some newer completion practices. A recently developed well completion tool. the production "packer hare" receptacle. is described.
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