Some Influences of Saturation and Fluid Flow on Sand Production: Laboratory and Discrete Element Model Investigations

Bruno, Michael S.; Bovberg, C.A.; Meyer, R.

doi:10.2118/36534-ms

Cited by 31 publications

(11 citation statements)

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“…The sensitivity of rock yielding, hence sand production risk, to this apparent capillary cohesion is one possible mechanism to account for the significant increase in sand production commonly experienced with increasing water cut. Bruno et al 18 demonstrated this effect with laboratory experiments, and with numerical modelling of a partially saturated assemblage of circular particles using the discrete element method. It is important to note, however, that these capillary effects are subject to change if the mineral grain structure of a rock is loosened, hence increasing the pore throat size.…”

Section: Apparent Rock Cohesion Due To Capillary Effectsmentioning

confidence: 92%

“…Vaziri et al 22 demonstrated the use of a tensile failure criterion for rock detachment during production from weak coal formations using a finite element model. Thallak et al 23 and Bruno et al 18 have used discrete element models to predict the development of borehole breakouts in an assemblage of spherical particles. The numerical analysis of rock detachment around a borehole for a strain-softening continuum remains relatively unexplored, and will be described in this paper.…”

Section: Numerical Modelling Of Sand Production Risksmentioning

confidence: 99%

See 1 more Smart Citation

Sand Production Prediction for Horizontal Wells in Gas Storage Reservoirs

McLellan¹,

Hawkes²,

Read³

2000

SPE/CIM International Conference on Horizontal Well Technology

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSand production and the sand control technique selected to mitigate or eliminate it can have a critical influence on the performance of horizontal wells in gas storage reservoirs. A completion that provides adequate sand control is usually required, but an overly conservative completion design can have an unnecessary, negative consequence on gas well productivity and injectivity. The selection of the appropriate sand control design depends on the characteristics of the reservoir formation, the in-situ stress state, the maximum and minimum values of the reservoir pressure during gas storage operations, the drawdown pressure, the near-well fluid saturations, the well trajectory and the capacity for handling sand in the well tubulars and surface facilities. This paper reviews the principal causes of sand production from borehole and perforation collapse, and demonstrates the application of commercial software programs for assessing sand production risks. The influence of formation damage, compressible and non-Darcy gas flow effects, reservoir pressure changes and rock strength reduction due to cyclic loading will be illustrated. Additional risks, such as exceeding the fracture breakdown pressure in the reservoir during injection, or collapsing weak, interbedded shale strata that are locally penetrated by the horizontal well, are also described. Numerical geomechanical modelling techniques suitable for more complex material behaviour and fluid flow phenomena are also described, as well as a novel procedure for estimating initial produced sand volumes.Several field examples are presented, illustrating results for reservoirs ranging from relatively strong rocks, in which no sand control is required, to poorly cemented sandstones which require gravel-packed or screened completions.

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Section: Apparent Rock Cohesion Due To Capillary Effectsmentioning

confidence: 92%

Section: Numerical Modelling Of Sand Production Risksmentioning

confidence: 99%

Sand Production Prediction for Horizontal Wells in Gas Storage Reservoirs

McLellan¹,

Hawkes²,

Read³

2000

SPE/CIM International Conference on Horizontal Well Technology

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“…To understand this, several experiments have been conducted (Bruno 1996). From arching experiments, it was found that grains without mechanical cohesion were only held by capillary cohesion.…”

Section: Effect Of Two-phase Flowmentioning

confidence: 99%

“…as the material strength of the rock. Bruno (1996) conducted experiments with a sand pack to study the effect of saturation on sand production. Observation showed that sand production required water saturation beyond irreducible water saturation as well.…”

Section: Effect Of Two-phase Flowmentioning

confidence: 99%

A Predictive Model for Sand Production in Poorly Consolidated Sands

2011

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This paper presents a sand production model that predicts the stability of wellbores and perforation tunnels, as well as the mass of sand produced. Past analytical, numerical, and empirical models on material failure and erosion mechanisms were analyzed. The sand production model incorporates shear and tensile failure mechanisms. A criterion for sand erosion in failed sand was proposed based on a force-balance calculation on the sand face. It is shown that failure, post-failure sand mechanics, and flow-dominated erosion mechanisms are important in the sand production process. The model has a small number of required input parameters that can be directly measured in the laboratory and does not require the use of empirical correlations for determining sand erosion. The model was implemented in a numerical simulator. Experiments using different materials were simulated, and the results were compared to test the model. The model-generated results successfully matched the sand production profiles in experiments. When the post-failure behavior of materials was well-known, the match between the simulation and experiment was excellent. Sensitivity studies on the effect of mechanical stresses, flow rates, cohesion, and permeability showed qualitative agreement with experimental observations. In addition, the effect of two-phase flow was presented to emphasize the importance of the water-weakening of the sand. These results showed that catastrophic sand production occurs following water breakthrough. Introduction A conventional and conservative approach to completing a sand-prone well is to install a mechanical means of sand control, such as gravel packs, fracpacks, and screens. In some cases, sand management is practiced through oriented perforating and rate control. An openhole completion can be an alternative to a cased and perforated completion to reduce the near-perforation fluid velocity. Before deciding on how to prevent or minimize sanding, the benefits and disadvantages of sand control/management must be evaluated carefully, and the assessment of qualitative and quantitative sanding risk is crucial. Many publications present sand failure and sand production models supported by experimental results (Hall and Harrisberger 1970). Some models deal with the problem of sand stability and failure (Bratli 1981; Risnes 1982). With the advent of numerical simulations, such as finite element modeling (FEM), sand production became a popular numerically simulated problem because of its complexity. However, most of these models rely on parameters that may or may not be experimentally measureable. In many instances, the physical significance of some of these parameters is not obvious. While most of the research work has generated relevant insights on sand production, a comprehensive model that can adapt to different experimental settings and to the field is not available because of one of two reasons: (1) a lack of model sophistication or (2) overly complicated models with excessive input requirements. This calls for a flexible and complete model with a quick runtime and a small and measureable set of parameters that provides reasonably accurate results. The purpose of this paper is to showcase a general 3D numerical model that describes the process of sand failure, erosion, and production quantitatively(Fig. 1).The sand production model incorporates two sequential phenomena. The first one is the failure of the near-wellbore region (wellbore or perforation), which is a necessary condition for any sand production. The subsequent step for sand production is "erosion." This process refers to the removal of the sand from the failed region. In the model, a force balance is conducted between the frictional forces mechanically holding the sand in the formation and the hydrodynamic force (exerted by the flow) that induces detachment of the disaggregated sand. Gridblocks for which the frictional force is overcome by the hydrodynamic force are removed from the simulation and are assumed to be produced into the well. The model is verifiable with distinct sets of experiments, which then could extend and offer a reasonable prediction tool for sand-production characteristics for field cases. The numerical model also obtains results that are beyond the reach of simpler analytical solutions.

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“…Several authors 8,9 have demonstrated channel formation in sand alone at very low flowrates, but cavity formation occurs at higher flowrates. 10,11 However, under the higher flowrates, typically seen following hydraulic fracturing applications, channels only form when fibers are present. 3,4 The fibers provide a higher critical flow velocity leading to more stable channels.…”

Section: Fig 1-laboratory Proppant Flowback Test Terminated After Inmentioning

confidence: 99%

Interaction Between Growing Channels in Proppant Packs: Length and Number of Channels

James

Lee

Howard

et al. 2000

SPE International Symposium on Formation Damage Control

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe formation of channels in propped fractures, in the presence of fibers, has been demonstrated experimentally under a wide variety of conditions. The presence of channels can have a significant impact on the effective fracture conductivity and consequently the productivity of a given well. While single channels are observed in experiments, a question is how many channels may be present in real proppant packs and how long do they grow? The length is especially important when proppant flowback control additives are used as "tail-ins" with the last part of the proppant pack. To complement the experimental study, the understanding of channel propagation and the interaction between multiple growing channels was modeled using finite difference codes.Modeling was performed using a 2-dimensional explicit finite difference program. The formation of channels was predicted by using two parameters -a critical flow rate and a curvature limit. Results demonstrated that the curvature limit is a critical parameter in determining the stability of channels. Calibration of the model with laboratory experiments with proppant and fibers provided clear explanation as to why channel formation provides proppant pack stability at high flow rates.For a given flow rate, channels grew until a stable length was attained; increasing the flow rate would cause the channel to grow further until a subsequent stable length was attained. Multiple channels were generated but a dominant channel grew once the length of the channel was greater than the spacing between channels. The presence of one, or several widely spaced, long channels will have a much larger impact on productivity than many short channels. Bilinear flow conditions resulted in channel growth to a stable equilibrium length. This is expected to occur in real fractures.A consequence of this behavior is that fractures should be flowed back at high rates to grow channels that will then be stable at subsequent production rates.

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Some Influences of Saturation and Fluid Flow on Sand Production: Laboratory and Discrete Element Model Investigations

Cited by 31 publications

References 0 publications

Sand Production Prediction for Horizontal Wells in Gas Storage Reservoirs

Sand Production Prediction for Horizontal Wells in Gas Storage Reservoirs

A Predictive Model for Sand Production in Poorly Consolidated Sands

Interaction Between Growing Channels in Proppant Packs: Length and Number of Channels

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