One unconsolidated heavy-oil reservoir has more than one hundred wells, some of them being horizontal with high production rates. One of the horizontal wells has a completion problem and another one has sand production problems. Additionally, there are concerns regarding stability of some of these horizontal wells during cyclic steam processes. The goals of this study were two folds. First of all, it is beneficial to evaluate the stability conditions for the two problematic wells and to determine possible remedial strategies, as well as procedures to avoid similar problems in the future. Secondly, it is informative to evaluate the stability of the horizontal wells during cyclic steam stimulation processes and assure that well operating condition does not induce excessive shear failure around the wellbore.
Borehole stability problems can dramatically increase the cost of drilling and completing wells. Sand failure and production may lead to costly well shut-in and workover, as well as equipment failure. Wellbore instability is particularly important when operating in deep unconsolidated formation or when horizontal wells are planned. It is important to evaluate the stability of these wells both for drilling and for production processes such as cyclic steam stimulation. Traditionally, analytical methods are used to predict required mud weights. However, they are typically too conservative and are unsuitable for applications to horizontal wells in unconsolidated formation.
In order to carry out the study, a wellbore stability model which can be coupled with a thermal simulator has been developed. The model uses a robust finite element elastoplastic code as the engine to perform effective stress analysis of the near-wellbore tensile and shear failure. The code is capable of handling extremely low confining stresses (near tensile regime) in unconsolidated formation. As plastic yielding occurs at relatively low deviatoric stresses under low confining stress condition, it is not a good indication of wellbore failure in terms of loss of service. Therefore, a more realistic criterion based on the accumulated plastic strain is applied.
The results from the stability evaluation of one of the horizontal wells are discussed. It is shown that the model gives reasonable agreement with field observations. Additionally, the results from some preliminary investigation of the effects of steaming on horizontal wellbore stability are included.
Formations at depth exist under a state of compressive in-situ stress. When a well is drilled, the rock adjacent to the wellbore must now carry the load which was supported by the removed material. This alternation in stress state adjacent to the wellbore wall can exceed the strength of the material leading to some form of failure. As drilling costs are expensive particularly with horizontal wells, it is imperative that the possibility of well failure be minimized.
Borehole failure can be broadly classified as either tensile or compressive. Tensile failure occurs when the wellbore pressure increases to exceed the tensile strength of the rock. Compressive failure occurs when there is insufficient wellbore pressure support. This can lead to rubbling (sloughing) in brittle formation, resulting in hole enlargement. If the formation behaves plastically, it will flow into the hole resulting in hole tightening. Rock behaves differently in tension than in compression and a separate failure criterion is required to describe each type of failure.
Tensile Failure. Rocks generally have low tensile strength.