HPHT wells represent one class of problems where the performance of current sand prediction models has not been properly evaluated. We applied three different sanding models to a cluster of six HPHT wells. In all these wells, no sanding was observed under considerable levels of drawdown, certainly far surpassing conditions required for sand failure. Moreover, under failed conditions, the wells were producing high rates of gas for very long periods. The approaches used included popular analytical shear failure and tensile failure based models which showed an unusually high level of conservatism in their prediction of sanding in high pressure wells. We provide a plausible explanation for this behavior which is attributed to the underlying proposition that sand production occurs when sand fails. While this supposition is used in all applications of such models, in deep, high stress and pressure systems, the problem is magnified due to the fact that failure occurs relatively early in the operating life of the reservoir. We propose an alternate approach where sand production criterion is extended to include not only sand failure but also adequate seepage forces to liquefy the sand and hence mobilize it. This approach is shown to better capture the observed response in the field. As an added bonus, the proposed approach quantifies the volume of sand rather than simply give indications of the onset of sand production. This information is helpful in developing the optimal production strategy throughout the life of field. In this paper, we discuss the pros and cons of the commonly used models for sand prediction and provide examples to validate the newly proposed concepts for quantifying sand production. Introduction This paper supplements a recently published paper1 which was focused on the issue of water impact on sand production. While the main emphasis of the current paper is centered around the validity of common analytical sand prediction models in application to high pressure, high temperature (HPHT) wells, some duplication of the material presented earlier is necessary otherwise the main framework for discussion of the findings will be lost and insufficient background and data would be directly available for a meaningful presentation of the findings. The objective of this paper is to show the performance of several common tools and techniques for sand prediction analysis in application to HPHT wells. There are two basic reasons for focusing the main efforts on HPHT wells:previous reported studies have not covered this class of problems, anddeep, over-pressured gas reservoirs more clearly and convincingly bring out the limitations of some of the assumptions embodied in the current approaches used for sand prediction. The basic discussions with respect to pros and cons and validations of different techniques for sand prediction ranging from purely empirical to mid-range analytical and rigorous numerical methods have been presented in a number of publications(e.g., 2–6) and we will do our utmost not to repeat the same messages or findings. Critical Review of Common Methods of Analysis For the sake of objectivity, purely empirical methods (those based on fitting future predictions based on existing trends observed in the field) are not covered here. We will discuss numerical and analytical methods with emphasis on the latter as these constitute the most commonly used ones.

Centrifuge physical model tests were performed to study the mode of failure during sand production and its concomitant impact on the productivity index. The tests simulated seepage-induced failure around a multiperforated vertical well. Results indicate that in the presence of a competent cap rock (1) sand production results in the formation of a truncated cone-shaped enlarged cavity; (2) surface subsidence of the reservoir due to loss of sand mass may result in the opening of flow channels under the cap rock; (3) for a given applied head difference, sand production ceases once the enlarged cavity reduces the pressure gradient to subcritical levels; (4) the flow becomes diverted towards the upper perforations where the cavity radius is largest; and (5) the flow rate increase varies between 5 and 10 times depending on whether the mode and volume of sanding is sufficient to result in the formation of flow channels. The study performed shows that (1) the location of perforations affects the mode and magnitude of sand production; and (2) long-term productivity can be improved through managed sand production. The presence of a competent cap rock is the key to achieving substantial increases (an order of magnitude) in productivity via sanding.Key words: centrifuge test, sand production, well-bore completion, subsidence, oil sand, flow improvement.

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