Based on research and model development, including a new rock strength model that considers the effects of both chemical reactions and capillarity changes, a new pressure model that calculates fluid pressure variations with water saturation, an improved nonlinearity model for rock deformation modulus, and a coupled analytical elastoplastic model for stress estimation, the mechanisms for sand instability have been identified, quantified, and compared to address the question of why sand often fails after water breakthrough in an oil well.
Model calculations indicate that, with increase of water saturation, sands tend to become weaker (strength reduction) and softer (stiffness reduction) while the loading stresses are elevated and the maximum shear stress moves outward into the reservoir (i.e. a larger zone is affected). For the case discussed, losses of both rock strength and modulus can be up to 80%, while the shear stresses can double because of fluid relative permeability changes and strength loss. Furthermore, after shear failure the sands are more easily detached from the rock matrix because of a decrease in tensile capillary strength with an increase of water saturation. Since the capillary strength is shown to depend only on water saturation, the sanding rate for each value of saturation is constant until destabilizing forces are changed, which leads to so-called episodic sand production after an oil well starts to produce water. These analytical tools can serve as a basis to develop more useful sand stability tools for multiphase fluid flow environments.
1. INTRODUCTION
Sands become unstable and start to flow after water intrusion even though no preceding sand production was observed [3,4], and massive sand production occurs when Sw reaches a particular value [6];
For sanding wells, the average sanding rate during water breakthrough is higher than before breakthrough [2];
The critical global pressure gradient that activates sanding drops when Sw increases [5]; and,
Sanding appears as an episodic phenomenon: at a given Sw, a sand cavity starts to grow and then becomes stabilized; additional cavity growth episodes require either an increase of pressure gradient or a change in the water saturation value [5,6].
It is estimated that, on average, companies produce three barrels of water for each barrel of oil [1], seventy percent of which comes from weakly consolidated or unconsolidated sandstone. The intrusion of formation water into water-wetted but oil-saturated sand, which is the usual case in oil fields, may trigger or worsen the sand instability that has been frequently observed both in the field [2, 3] and in the laboratory [4-6]. Some characteristics of water-related sand production are:
Chemical reactions between water and solids and the dissolution of cementitious materials may weaken the rock;
Changes in the surface tension and capillary force may lower the cohesive strength;
Extensive experiments have been carried out to study the effect of changes in Sw (or moisture content, humidity, etc.) on different rock samples, such as shale [7, 8], chalk [9-11], and sandstone [2, 5, 12-15]. The various possible mechanisms may be generalized as follows [16]:
