Differentially Stuck Pipe: Early Diagnostic and Solution

Abstract

Abstract Problems with differentially stuck pipe account for huge losses in the oil industry all over the world. Being able to minimize the risk of getting stuck while drilling has been the goal recently. However, some misunderstanding and misinterpretation of current laboratory and rig tests have led operators to apply the wrong solution to the problem. This paper initially addresses how the drill string gets differentially stuck and the main related mechanisms. The old concepts and ideas are revised here on the basis of new drilling fluids being used, especially the ones with low solids content. The simplest solution for minimizing the risk of getting stuck is described, as well as some field indications of how the problem can be detected at an earlier stage. The paper finally shows the importance of changing the way some tests are conducted today to clearly quantify the risks involved in any drilling operation. Introduction Differentially stuck pipe (DSP) occurrences are common everywhere1, and account for a significant amount of non-productive time and ends up as one of the major causes of increased well costs. In some areas, events related to differentially stuck pipe can be responsible for as much as 40% of the total well cost. The risks of DSP increases when drilling depleted reservoirs, and, due to the low profitability of such projects, any undesired event could hurt the economics of these developments. Therefore, in some instances it is critical to reduce as much as possible the risks associated to DSP. Even though this is an old problem, with new drilling fluid technology, especially related to the use of low and ultra-low solids fluids, there is a need to reevaluate the true mechanisms that lead to a DSP. In this paper, some of the old concepts are questioned and discussed, and a simple description of the problem is proposed. Also, field cases are presented describing what are the signals that can be detected during drilling, indicating a high risk of having the drill string stuck. Based on the most recent trend of using drill-in fluids, with low and ultra-low solids content, the best option to reduce the risks of DSP is suggested. A simple laboratory test to assess this risk is proposed; three drilling fluid has been tested and the results interpreted in the light of this new understanding. Simple Description of the Problem Traditionally DSP problems have been related to a thick cake built at the side of the wellbore wall combined with a relatively high differential pressure (pore pressure minus the fluid pressure inside the wellbore, Fig. 1). Based on this understanding, several studies have been conducted to design drilling fluids that generate a thin cake. The plasticity of the cake was also subject of investigation by several companies. Since most of the time it is not possible to reduce the differential pressure while drilling a depleted reservoir, i.e. interbedded shales require high mud weight to keep them stable, the option was to act on the mud cake. The cake was also responsible to avoid invasion of the drilling fluid (usualy thought to be the filtrate) into the formation. The permeability property of the cake, as well as ways of effectivelly remove it were also important subjects studied in the past. New drilling fluid technology is more and more tending to the use of low and ultra-low solids mud. These fluids do not build a mud cake in the same way the old bentonite systems used to do. Usually, the sealing mechanism is generated inside the rock, leaving just a thin film on the outside. Therefore, one of the most critical items in preventing DSP has been taken care of, by virtually eliminating the cake. But, the problem still persists while drilling oil/gas wells, which means other things are also playing an important role in the problem.