RIASSUNTO
Abstract
The use of continuous coiled tubing to perform various types of remedial treatments or workovers has been well documented. Numerous successful treatments have been obtained with this device in oil, gas, injection and geothermal wells. However, the occurrence of and, more importantly, the causes of failures in operations involving coiled tubing have not been addressed by the industry. An examination of causes of failure should lead to a higher success ratio.
Introduction
Of the various types of workover operations currently available, the most cost effective in many instances is the use of continuous coiled tubing. Oftentimes, the coiled tubing may be applied in the same manner as the commonly employed small diameter wash pipes to form concentric strings within wellbores. There are, however, important differences between jointed pipe and the continuous, reeled tubing which must be considered.
Instances of stuck or collapsed coiled tubing have resulted in costly fishing operations and lost revenues due to extended shut-in periods. The author proposes that many of these failures stem from a lack proposes that many of these failures stem from a lack of consideration as to the unique characteristics of coiled tubing, the more important of which are that it is relative to jointed pipe, a thin walled, highly flexible welded string of which a portion is exposed to the atmosphere during use. These features which impart versatility to the coil unit are the same which, if neglected, contribute to failures. It is felt that in these cases the fault is not due to an impracticality of the continuous coiled tubing unit as a workover device but rather to deficient or, in some cases, a complete lack of consideration as to the proper design of such treatments. Common applications proper design of such treatments. Common applications of coiled tubing will be examined with attention to the areas of possible misuse.
REMOVING FILL FROM WELLBORES
Frequently tubing units are utilized to remove solids from wellbores. The solid material may be propping agents left in the wellbore subsequent to propping agents left in the wellbore subsequent to screen-out of a hydraulic fracturing treatment or matrix material which feeds into the wellbore from unconsolidated formations. The units are particularly well suited to remove this fill from casing below a packer assembly. While in most cases these treatments packer assembly. While in most cases these treatments are performed perfunctorily, there have been cases where the coiled tubing has become stuck and which resulted in the need to fish the tubing from the well.
It is apparent that this type of operation is frequently designed along arbitrary guidelines as to selection of wash fluid, circulation rate and tubing injection rate. In the majority of wells these considerations are nominal. They become critical when washing in larger diameter ( greater than 5 "" O.D.) casing or in wells with mechanical peculiarities such as helically buckled production tubing, side pocket gas lift mandrels or an unusually high degree of deviation from the vertical. Certain guidelines may be followed which should reduce the occurrence of stuck tubing in this process.
FLUID SELECTION
Generally speaking, solid particles such as sand settle in fluids at some given rate. In the so-called perfect support fracturing fluids this rate is nil, perfect support fracturing fluids this rate is nil, but in fluids which are more Newtonian in nature and less viscous, the particles settle faster. The relevance of this fact to fill removal via coiled tubing is to select a fluid wherein the terminal settling velocity of particles such as frac sand is less than half the rise rate of the fluid in the created annulus. Given that the rise rate of the fluid is a function of the circulating rate through the coiled tubing and considering, the relatively small ID of the tubing, trade-offs occur which affect selection of the proper wash medium.
As the circulating rate through the coiled tubing is related to the injection pressure of the fluid, the excessive friction loss values of untreated waters or the more viscous fluids can give rise to pumping pressures which can exceed operating limitations for pressures which can exceed operating limitations for that portion of the tubing exposed to the atmosphere. The choice of fluid is therefore made to achieve adequate viscosity versus minimum friction loss which in turn equates to maximum circulation rate.