Understanding Formation (In)Stability During Cementing

Abstract

Managing formation (in)stability should be an integral part of well construction from drilling through cementing and completion operations. Formation (in)stability while drilling has been recognized and is an ongoing study in the petroleum industry. Most of the emphasis in these studies has addressed the interactions between drilling fluids and formations, as well as, the geomechanical aspects. However, if the wellbore is stable at the end of the drilling phase, but the cement and spacer properties are not optimized accordingly, the formation could be destabilized during cementing. Such an event could negate much of the prior effort toward controlling instability. Destabilization could adversely impact the well construction and overall field development throughout the well's lifecycle. As the rock material is removed and replaced by a drilling fluid and subsequently displaced by cementing fluids (spacer and cement slurry), stability of the wellbore should be ensured by applying an adequate net radial support to the formation. The borehole pressure exerted by these fluids can counteract the near-wellbore effective stress concentration created while drilling. If the radial support applied to the formation is inadequate, the stress concentration can exceed the formation compressive strength, leading to borehole collapse. On the other hand, excessive borehole pressure can lead to lost circulation problems if the near-wellbore tangential (circumferential) stress and the formation tensile strength are exceeded. As the formation is exposed to drilling and cementing fluids, the near-wellbore effective stress concentration is altered because of the formation fluid's physicochemical interaction. Such alteration of the effective stresses and formation properties can result in time-dependent stability problems. Introduction Wells drilled through young sediments that exist as highly reactive shales and silt stones are an integral part of oil and gas operations in most parts of the world. Cementing fluids often include various salts (e.g. NaCl, KCl, and CaCl2) for various purposes, such as intentionally affecting (shortening) slurry set times, cementing across salt formations, and supposed protection of productive formations that may contain water-sensitive clays. Historically, salt content in cement slurries has varied from 1 or 2% to saturation with NaCl. Use of KCl and CaCl2 is usually limited to no more than 3 or 4%. However, the use of salts in cement slurries is not consistent with respect to formation issues. The position is frequently taken that the high pH of cement slurry, along with its minimal amount of calcium in solution, will suffice to provide protection in most cases. However, very little actual supporting evidence for this assumption has been found. Furthermore, most documented test reports have been based on regained permeability testing of sandstone cores. Although very meaningful to the understanding of a specific issue, any connection between effects on clays in permeable sandstones and formation (in)stability as related to shales is complicated by precipitation of various calcium salt species from cement slurries.1 The pros and cons of this issue are frequently debated with no clear consensus, and when salts are applied presumably for formation stability purposes, it is frequently done without a true understanding of the method or outcome. Additionally, use of salts in cementing spacers and preflushes is seldom applied. In addition to salts, there are many other additives in cementing fluids. Polymers of many types (e.g. blends containing HEC, CMHEC, and various synthetic polymers) as well as silicates are frequent components in cement slurries. These additives can serve several functions, including prevention of slurry dehydration and annular bridging during placement, enhanced bonding across permeable zones, rheology adjustment, and as an aid to gas migration control. However, combining salts and fluid-loss additives in the same slurry frequently presents a more complicated and costly scenario because many fluid-loss additives do not hydrate and/or otherwise function as efficiently in the presence of high concentrations of soluble salts. The authors believe that this cost-driven approach to achieving cement slurry fluid-loss values has resulted in the reduction and general elimination of salts in many primary cementing slurries, without a true understanding of the resulting effects on wellbore stability.