Abstract Shale gas reservoirs are mainly characterized by their low permeability and by having geomechanical, petrophysical and geological characteristics different from conventional reservoirs. Successful production of this type of reservoir depends on two aspects, its hydrocarbon generation potential and the ease of extraction. Therefore, characterizing and determining the natural fracture zones that will be connected by the drill bit and hydraulic fracturing is essential before orienting and defining the well trajectory. This article will characterize reservoir properties in terms of its geomechanics and petrophysics, specifically rock brittleness, since they are the main determining factor for selection of shale gas reservoirs with potential to be exploited. Brittleness is determined from geomechanical properties, consequently, indicating higher brittleness values to rocks with high Young's modulus and low Poisson's ratio, which translates into rocks rich in quartz, and lower values to rocks with low Young's modulus and high Poisson's ratio due to its organic richness and high content of clay minerals. This brittleness index involves the following properties: elastic and resistance parameters, pore pressure, total organic matter content and porosity, which show changes according to the different compaction trends that the rock has undergone. Finally, the evolution of pore pressure and compaction trends as a function of time will be analyzed to determine rock brittleness at each stage of burial. Concluding that rocks prone to fracture present overpressure, a high Young's modulus, and a low Poisson's ratio, have low porosity values and TOC between 1% and 3%. Introduction In recent years, shale gas reservoirs have been considered as a potentially economic resource, thanks to the high energy demand evidenced in countries such as the United States of America where natural gas consumption was 31.01 trillion cubic feet (EIA, 2019), and the technological development that has allowed its exploitation. However; the study and characterization of this type of reservoir turns out to be complicated, because they are reservoirs that have a matrix with ultra-low permeability and are notably different from conventional reservoirs, in terms of their geology, geomechanics and petrophysics (Dewhurst et al., 2015). In addition to their total organic matter content that makes them an interesting area. Therefore, to generate production from this type of reservoir, not only artificial fractures are required but also natural fractures, which constitute important flow channels (Nordeng, 2009), however, the little study of this type of fractures in reservoirs unconventional means that the success of its commercial production is not guaranteed. Therefore, the need arises to characterize properties of shale gas in terms of geomechanical and petrophysical attributes that intervene in formation of fractures. The methodology developed will allow oil companies to correctly select the candidate strata to fracture and, therefore, to create flow channels to wells.

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 geomechanical model for mud density optimization is essential to guarantee drilling success. This will allow to avoid problems such as: wellbore collapse, influx, induced fractures, pipe sticks, among other aspects that contribute on cost increasing and NPT. Normally, conventional wellbore stability models do not include mud losses effects through fractured zones. This research proposes a new algorithm (or methodology) for modeling the mud losses phenomenon through fractured and permeable formations. This model includes fracture deformation, mud rheology, flow through fractures and a coupling between fractured zone and permeable zone, considering that fracture plane walls are permeable, generating losses rate maintained over time when corrective actions are not taken at field. This proposed algorithm solves mathematical models in both analytical and numerical methods, using finite differences, in order to analyze the circulation losses in a more robust way. Therefore, differential equations were used for fluid flow modeling, and analytical equations for formation properties, when these are not available. For fracture behavior, a linear relationship is assumed as a function of pressure, and mud rheology is represented by power law behavior. The mentioned algorithm allows to determine fracture width in real time, by circulation losses information. Moreover, it allows to calculate the maximum mud weight. Concluding, the mathematical model can be used in two way, when the fracture walls are impermeable and the fracture length is finite, ballooning phenomenon is modeled. Instead, when the fracture walls are permeable, it represents circulation losses phenomenon.

Abstract In unconventional shale reservoirs, the quality of completion is driven by the brittle failure, which means that the rock exhibits low plastic deformation. Several authors have proposed to evaluate the failure mode of the rock through a brittleness index that has been associated with the elastic properties and the mineralogical content. However, brittleness index could not represent the failure mode of the rock, because the elastic properties and the mineralogical composition are not related to the failure mechanism. Another concept called fracability index was introduced to define the degree of easiness to which a formation can be fractured; the most fracable intervals are usually spot that require less energy to fracture. Brittlennes and fracability indexes have been incorporated by the industry for the optimization of the completion, although in some cases the efficiency of the hydraulic fracture was not achieved because the role of the stresses on the completion could be omitted. In tectonically active basins, horizontal stresses can be highly influenced by the tectonic component, which in turn is affected by the elastic properties of the formation. In this paper, a case, validated with laboratory data, of selection of completion quality - the best hydraulic stimulation intervals–for Cretaceous formations for a specific area of Magdalena Middle Valley basin in Colombia is presented, based on variables such as the brittleness index, fracability index and stresses. In this scenario, it turns out that the brittlenes and fracability index alone is not enough to identify the best intervals to fracture. Additionally, in the intervals where the brittleness index suggests the completion quality, it was observed that it corresponds to the depths where the minimum horizontal stress increases. Finally, the completion quality could be defined by understanding the relationship of the elastic properties on the brittleness index, fracability index and stresses

Abstract Ecopetrol S.A has focused on drilling deviated and horizontal wells for the development of mature oil fields in four onshore basins in Colombia with high tectonic stresses and geological faults: Llanos, Putumayo and the Middle and Upper Magdalena Valley. In these mature fields, the reservoir pressure has decreased and this condition often leads to drilling problems, such as mud losses, differential stuck pipe and pack-off in reservoirs with shale intercalations. Additionally, continuous geomechanical analyses of prospect wells have been completed to mitigate borehole instability in the overburden and reservoirs in these basins Ecopetrol S.A and ICP have integrated multiple disciplines to approach these challenges. This integrated approach includes seismic interpretation of highlighted linear discontinuities with fluid channeling potential, drilling fluid engineering to mitigate the effect of weak bedding plane and pore-pressure heterogeneity, wellbore stability analysis, along with the application of technologies such as managed pressure drilling (MPD) for avoiding mud losses and formation damage while drilling the reservoirs. In addition, 1D geomechanical models were built for the estimation of mud weight windows, critically stressed natural fractures analysis and optimal well trajectories. Furthermore, extensive triaxial test results on rocks has been implemented in the geomechanical models. Finally, real-time wellbore stability monitoring has been implemented to reduce non-productive time (NPT) during the drilling campaigns.

Abstract Hydraulic fracture stimulation is the single most important technology which unlocks vast unconventional resources. Hydraulic fracture design requires a good knowledge of subsurface stress regime, especially the anisotropic minimum in-situ stress profile to determine landing zone and fault type. Field injection tests such as micro-frac and mini-frac provide the best estimates but they are costly and often limited to a few formation layers. It is now common to obtain in-situ stress profile using sonic logs calibrated to field injection test data. Log based in-situ stress determination assumes knowledge of rock's elastic properties. For conventional sandstone, assumption of isotropy is reasonable, but for highly laminated and heterogeneous shale rock system, isotropic assumption proves inadequate. In finely thin laminated layers, the sonic logs average over large intervals and might not provide full representation of the lithology variations. Laboratory core testing data enhances well logs and provides parameters necessary to illustrate anisotropy behavior. Lately, vertically transverse isotropic elasticity (VTI) is commonly invoked in stress estimation. VTI requires knowledge of 9 parameters compared to only 2 for isotropic elasticity. Methods to estimate these parameters in VTI model exist. The most challenging aspect is to get determine an off-diagonal parameter (C 13 ) in the elastic matrix. Here, we outline a coherent lab-based, deterministic approach to obtain all these parameters, combined with borehole sonic logs to derived minimum in-situ stress for shale rock systems. Novel acoustic sensors and measurement technique have been developed to obtain velocity profiles on one single representative rock sample at multiple angles (0, 45, 90 degrees). The associated Biot coefficients in the vertical and horizontal directions can now be derived. The resultant stress profile shows great variability due to the rock's heterogeneity. The experimental approach and comparison of results to field data will be presented. Laboratory methods upon the characterization of stiffness parameters for VTI model is well published and beyond what this paper is intended for. It is mainly focused on the mechanical properties' measurement as a function of orientation vertical, horizontal, and 45. Technologies have been developed in obtaining a vertical and horizontal plug, however the challenges remain in place to obtain a 45 plug in laminated material without possible damage or alteration of the mechanical properties. Upon a full review of the available literature it was determined that that needs for the estimation of the C 13 parameter is associated with the Vp45 compressional velocity. Due to the experienced difficulties with the acquisition of a 45 plug, efforts were focused to develop a 45-degree polarized transduce to measure Vp (45°) during the using a vertical plug. Multiple measurements were conducted using outcrops and reservoir rock from multiple formations across to validate of the measurement accuracy. Final results indicate consistency between the measurement on a carefully machined 45 plug vs. the measured Vp(45°) velocity from a vertical plugs.

SUMMARY: This paper will provide an overview about the use of geomechanics in improving heavy-oil production. If high recovery factors are sought, production of heavy-oil reservoirs requires stimulation to reduce oil viscosity. Intelligent use of geomechanics can create additional porosity and permeability by managing rock dilation and fracturing behavior. As a result, new areas are created for injected stimulants to contact the heavy oil, speeding up viscosity reduction and improving oil production. Additionally, the same mechanism can break down the permeability barriers in the reservoir for the injected stimulants to travel through, ultimately improving the reservoir recovery factor. Using field examples, this paper illustrates theoretical mechanisms and field results. It will hopefully provide a new paradigm for operators when planning their heavy-oil production, because geomechanics is both a necessity and a means to value creation. 1 INTRODUCTION Becoming an increasingly important component of global energy supply, development of heavy-oil resources has attracted world attention. Heavy-oil development in Canada and Venezuela, as well as in other countries such as China, the former Soviet Union, Indonesia, Oman, Russia, and the U.S., are some well-known examples, although the list is definitely not exhaustive. In the recent years, Kuwait, a traditionally conventional oil producer, has embarked on an ambitious mission to develop its heavy-oil resources. Therefore, it is timely to have the worldwide geomechanics community turn their attention toward heavy-oil development and how geomechanics can proactively help improve production rates, increase reservoir recovery, and minimize its environmental footprint (on air, land and water).

SUMMARY: This work presents a methodology for mud losses mechanism evaluation based on geomechanics of fractures. Several and catastrophic mud losses events are continuously experienced during drilling the 8½̈section in Castilla Field in Llanos basin, Colombia. Technologies like Manage Pressure Drilling (MPD), thixotropic fluids, LCM (Lost Control Materials), ECD (equivalent circulating density) management were applied to avoid/manage mud losses but the issues associated to mud losses continue being a major problem causing among others wellbore instability in K1 superior formation due to fluid static column variations. According to the events, wellbore instability becomes the new problem causing hole cleaning issues, tight hole and restrictions tripping drill pipe and 7̈ liner. In image logs were detected several natural fractures both open and partially open. Fracture´s hydraulic conductivity hypothesis was proposed. To better understand the problem an evaluation of critically stressed fracture analysis was conducted by estimation of normal and shear stresses in each fracture plane assuming pressure transmission from the wellbore to the fractures. Geomechanical parameters estimated for each interval in which fractures were identified, entered the analysis as an input. Then, the fracture´s stresses were compared to the rock´s failure envelope assuming no cohesion in the planes. As a result, was figure out a reactivation gradient, which is compared to the pressure losses estimated based on the static column height in wells that experienced mud losses. The main observation is that there exists a fracture reactivation pressure lower than the minimum horizontal stress gradient and close to reservoir´s pressure that if is overcome, mud losses take place. 1 INTRODUCTION Fractures are discontinuities that create escape paths for drilling fluids and thereby constitute an important mechanism of lost circulation. Most rocks contain fractures of various sizes from micro cracks at grain level to fractures extending for hundreds of feet in the reservoir. In some reservoirs, fractures provide important pathways for the reservoir fluids. Connectivity of the fracture network is its essential property. In the lost circulation context, it affects how much drilling fluid can be lost. In natural fractured reservoirs, the availability of a connected fracture system is essential for production, but is detrimental for drilling (Lavrov A, 2016).

SUMMARY: After the success of the drilling campaigns in unconventional shale reservoir in the United States, Ecopetrol wanted to replicate their success in Colombia as well. During the past years a drilling campaign encountered several unique issues for shale plays in Colombia. With the advances in electrical logging, petrophysics, geomechanical and geochemical analyses allowed understanding the shale plays in a basin in Colombia. Geomechanics has been useful in providing the required information for the design of optimal well trajectories for efficient development of unconventional reservoirs. Additionally, extensive tri-axial and total carbon organic (TOC) tests in shales have been included in the study to calibrate the mechanical properties and TOC obtained from the electrical logs. The concept of critically stressed fractures has been included in the analysis of this geomechanical model in order to know the conductivity of the natural fractures in shale plays. The present study displays a methodology for the design of a mud weight window as well as a geochemical analysis for the sweet spot selection in the shale plays. The geomechanical model considers transversal vertical anisotropy (TIV) with the use of Stoneley wave from sonic scanner tool necessary for the determination of the anisotropic mechanical properties and in-situ principal stresses. The present study includes conclusions and recommendations for unconventional shale reservoirs in Colombia. 1 INTRODUCTION Oil companies have always wanted to drill wells in unconventional fields, but because of their complexity and limited technology in the time were an impediment.