(79913)_Understanding_Formation_(In)Stability_During_Cementi(2)

钻井固井

2 SPE/IADC 79913

formation instability as related to cementing operations, and to

provide a link to current developments in water-based mud technology regarding the same subject. Experiments presented here show that maintaining formation stability with cementing fluids can be just as important in reducing problem well costs as maintaining formation stability with drilling fluids. This maintenance can be achieved through a combination of osmotic outflow of pore fluid (chemical potential mechanism) and prevention/minimization of wellbore fluid pressure penetration. The data presented show that wellbore fluid pressure penetration can be prevented by generating an isolation membrane on the borehole wall. Penetration can be reduced by minimizing hydraulic diffusivity; the two OBMs, recent developments and understanding of membrane-efficient WBMs have started to overcome these deficiencies in regard to formation stability.2

Problems with Conventional Water-Based Muds, Spacers, and Cements

Past efforts to develop improved WBM for shale drilling have been hampered by a limited understanding of the drilling fluid/shale interaction phenomenon. This limited understanding has resulted in drilling fluids designed with inadequately optimized properties, which are required to prevent the onset of borehole instability problems in shales. Historically, wellbore (in)stability problems have been procedures can also be combined.

Background

Shales are fine-grained sedimentary rocks composed of clay, silt, and in some cases fine sands. For this discussion, shale will be considered a loosely defined heterogeneous argillaceous material ranging from clay-rich gumbo (relatively weak) to shale siltstone (highly cemented). Both types will have extremely low permeability and contain clay minerals. Argillaceous formations like shales make up over 75% of drilled formations and cause over 90% of wellbore instability problems. Instability in shales is a continuing problem that results in substantial annual expenditure by the petroleum industry — in excess of a billion dollars, according to conservative estimates. Shales in the upper hole sections where surface and intermediate casings are set, as well as those overlaying drilled, deepwater reservoirs, are typically geologically young. Generally, these formations are poorly consolidated and can cause a significant proportion of wellbore instability problems.

A drilling fluid system (drilling mud) is an essential part of a conventional drilling process and consists of different solid and fluid components. From the standpoint of the shale, cementing fluids are basically the same. Different components may be added to any of these fluids to help enhance their performance. Main functions of a drilling fluid include the removal of rock material during drilling, imparting hydraulic support to the borehole to help ensure stability, providing lubrication to reduce friction between the borehole surface and drillpipe, cooling the drill bit, etc. Cementing preflushes and spacers removes the drilling fluid in preparation for the cement slurry and separates potentially incompatible drilling fluids. Finally, the cement will serve the ultimate function of zonal isolation and structural support. The properties of all of these fluids are adjusted to account for the changing characteristics of wellbore formations encountered.

In the past, oil-based and/or synthetic-based muds (both referred to throughout this paper as OBMs) have been the systems of choice for difficult drilling. Their application has been typically justified based on borehole stability, thermal stability, fluid loss, lubricity, etc. Today, environmental concerns and the availability of synthetic fluids restrict the use of oil-based muds. As a result, innovative means are needed to obtain OBM performance without negatively impacting the environment. Water-based drilling fluids (WBM) are attractive replacements from a direct cost viewpoint. While conventional WBM systems have failed to match the performance of approached on a trial-and-error basis, going through a costly multiwell learning curve before arriving at reasonable solutions for optimized operations and systems. As will be discussed, the same symptomatic approach has been observed for cementing operations, particularly with reference to leakoff testing. Studies of fluid/shale interactions offer insights into the underlying causes of borehole (in)stability, and these studies suggest new and innovative approaches for designing water-based drilling fluids.3 These concepts and ideas will be expanded in this project to include cementing fluids.

When drilling and cementing with water-based fluids under an overbalanced condition in a shale formation without an effective flow barrier present at the wellbore wall, mud pressure will penetrate progressively into the formation. Because of the saturation and low permeability of a shale formation, penetration of a small volume of filtrate into the formation can result in a considerable increase in pore fluid pressure near the wellbore wall. The increase in pore fluid pressure can reduce the effective wellbore fluid support, which leads to a less stable wellbore condition. Although the exposure time associated with cementing fluids will be much shorter compared to the exposure to drilling fluids, the same potentially destabilizing mechanisms are present until the cement slurry hydrates and filtrate availability is minimal.

Empirical Observations: Field Studies

One of the most common measures for gauging the success of a primary cement job on a surface or intermediate string of casing is a formation pressure-integrity test. This test may be performed as either a leakoff test (LOT) or simply a formation-integrity test (FIT) without going to leakoff. The causes of failed integrity tests are typically attributed to either channeled cement …… 此处隐藏：4761字，全部文档内容请下载后查看。喜欢就下载吧 ……