Abstract Several reservoirs experience the phenomenon of producing fluids with some quantities of formation solids. This phenomenon, known as “sand production”, occurs and affects many of the processes performed in a wellbore/reservoir and is one of the main factors causing problems related to project increasing costs with early equipment and facilities deterioration, low hydraulic conductivity between wellbore and reservoir and sometimes complete well lose. The objective of this article is to present a methodology for selecting sand control or sand management as strategy to implement in sanding wells. This methodology, based on literature experiences, accounts for reservoir properties, fluid characteristics and completion variables for the selection of a strategy. In order to select correctly the strategy to implement in sanding wells either sand control or sand management, a two steps methodology is proposed. The first step allows to identify the better option between sand control or sand management for each case. Based on the previous step, the second step allows to identify the best way to implement each strategy. The present methodology helps to solve the difficult decision of either implement sand control or sand management through easy steps. This, using direct information of wellbore production and reservoir variables. The use of this methodology will allow for a better and faster decision making related to sanding wellbores treatment, reducing complex and unnecessary studies when those are not required. Introduction Sand production occurs mainly in Poorly or unconsolidated formations, when forces of fluids in movement are enough to drag grains from formation sand. Produced solids can come from either the formation face or cavities or they can be fines coming from inside the reservoir. These solids can be produced for different reasons, therefore, to face sand production it is important to know the mechanisms involved in sanding. Some variables causing sand production are: pressure drop, depletion, in situ stresses, the water weakening effect, completion, drilling, and operational conditions (Araujo, 2015). For sanding wells, three options should be analyzed: Management, control or prevention. Sand Management refers to producing fluids with sand (with equipment erosion risk) improving porosity and permeability, hence productivity. Sand Control implies including filters in the bottom hole to prevent the transport of sand along with the fluid using mechanical or chemical means (Venkitaraman, Manrique, & Poe,. 2001). Sand Prevention does not involve control methods and depends on predictive models to identify the best drilling and production parameters that can delay sanding onset as much as possible in the life of the well (Venkitaraman, Manrique, & Poe,. 2001).

Abstract The interaction of hydraulic and natural fractures limits the successful hydraulic stimulation treatments and enhanced production in unconventional reservoirs. In this context, the numerical models become indispensable for understanding hydromechanical mechanisms present in the hydraulic stimulation and the production of naturally fractured formations. This work presents a fully coupled hydromechanical approach to study the hydraulic fracture stimulation in naturally fractured formations and its effect on the production performance in unconventional reservoirs. The proposed methodology is based on the finite element method (FEM) and includes the coupling of fluid flow and geomechanics within the permeable rock formation and the fracture propagation process. An intrinsic mesh fragmentation technique is used to simulate non-planar fracture propagation with complex crack patterns. A pore cohesive zone model is used to simulate hydraulic fracture propagation, and the Mohr-Coulomb failure criterion is adopted to model closure/opening and friction/shear dilation of natural fractures. Several scenarios considering a complex fracture network are investigated to understand the dominant factors influencing hydraulic fracturing and the production performance in unconventional reservoirs. Introduction The hydraulic fracturing technique is dispensable in the development of unconventional reservoirs with ultralow permeability. The efficiency of hydraulic stimulation is strongly affected by the presence of geological discontinuities such as faults, joints, and natural fractures (Barbier, 2002; O’Sullivan et al., 2001). Geological discontinuities reduce the mechanical strength of the overall rock mass and alter the fluid flow characteristics. Pre-existing fractures can be partially or completely cemented. They can act as barriers for flow paths depending on the permeability of the filling material (Warpinski & Teufel, 1987). Sealed fractures can be stimulated by hydraulic fractures (HFs) and become preferential flow channels for oil/gas exploitation (Rueda Cordero, Mejia Sanchez, & Roehl, 2019a). In that sense, the hydraulic stimulation aims for the activation of natural fractures (NFs) and/or generation of new induced fractures to enhance permeability and well-reservoir connectivity (Shahid et al., 2016). However, the interaction of induced and pre-existing fractures increases the complexity of the hydraulic treatment and the geometry of the stimulated fracture network (Stephenson et al., 2018; Weng, 2015; Zhang et al., 2019). Field and experimental observations showed different interaction types between induced and natural fractures (Jeffrey et al., 2010). Figure 1 illustrates the interaction process between fluid-driven fractures and pre-existing discontinuities. During the injection process, natural fractures can act as preferential paths for the growth of the hydraulic fracture network or arrest the hydraulic fracture propagation in some directions (Wang, 2016). In some cases, activated fractures can generate high proppant concentration and premature blockage of the proppant transport (screen out) (Potluri et al., 2005).

Abstract The important participation of Colombian heavy oil fields at the country oil production and the current thermal recovery operations implemented for their exploitation have brought about the need of a proper characterization and understanding of the reservoir mechanical and petrophysical properties under different pressure and temperature conditions. According to this current demand, the present study aims to analyze and assess a set of 19 triaxial tests focusing on the behavior of petrophysical properties (porosity and permeability) in representative reconstituted samples of an uncemented formation. Among these triaxial tests, different condition of temperature, confining pressure, drainage, and loading conditions (DTXC, UTXC and DRTXC) are carried out in order to replicate the conditions occurring to the formation during thermal recovery processes and estimate the effects of these variations on sample’s properties. The analysis shows a direct dependence between the petrophysical properties and the confining pressure. In tests carried out under high confinement (effectives stress greater than or equal to 4 MPa) the porosity decreases during shear stage, whilst under low confinement (effective stress of 0.4 MPa) porosity increases during shear stage. On the other hand, the permeability decreases before and after the shear stage in tests with high confinement, whilst at low confinement values, permeability increases. Lastly, an especial case of stress path for the undrained triaxial tests is presented which shows an asymptotic behavior in the stress path describing the Mohr Coulomb failure envelope. This especial case of stress path could be useful to evaluate Mohr Coulomb failure envelope using a single sample. Introduction Hydrocarbon reservoirs are subjected to different stress path during its productive life. Depending on the production/injection processes the rock can be subjected to a stress state where the horizontal stresses reduce (production) or increase (injection) (Morales-Monsalve et al., 2018). Besides, according to the redistribution of stress and pressure around the wellbore, the vertical stress might change (Ikogoll et al., 1989).

Abstract Cold heavy oil production with sand is a primary recovery method extensively used in the world as a profitable and simple technology. CHOPS is a single well technology that involves the deliberate initiation and sustaining of sand inflow into the wells using progressive cavity pumps to produce at oil high rates with a subsequent high-pressure drawdown around the wellbore and improvement in oil well productivity. Foamy-oil flow and wormholes formation are the main mechanisms of aggressive sand production. The wormholes are channels of high-porosity and high-permeability, which are generated during the early stage of massive sanding. These channels are cavities or volumes full of slurry, in which there is no grain-to-grain contact. An alternative methodology is proposed to model the initiation and propagation of wormholes incorporating failure criteria, and porosity and permeability changes during sanding under critical production conditions. The wormholes initiate due to in-situ stresses, failure criteria, pressure gradient, and erosion, which define four zones around the well: liquefied zone, yielded zone, transition zone and intact zone, each one with different mechanical and petrophysical properties, which are changing during the oil and sand production. A single well model that couples a three-phase fluid flow model and an elastoplastic model is the tool to apply the wormhole methodology. The general characteristics of the coupled model are described in detail, a flowchart is presented to display the methodology and the delineation of the four different zones. A preliminary case is run to demonstrate the wormhole formation and its effect on the well productivity with suitable results in terms of increment in porosity and permeability, and the advance of the wormhole.