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 Fault interpretation in seismic volumes is an essential task to understand the structural geology of the subsurface and a key role in decision-making related to well planning and reducing operational risks. During the last decades, it has developed seismic attributes based on different algorithms which preserving and highlighting amplitude discontinuities that typically are associated with faults. Moreover, distinct methodologies and workflows have been proposed to highlight and identify geological faults in seismic data as of the unification of those attributes. In the present project, we analyze different types of seismic attributes available in seismic interpretation software such as dip-steered median filter, structural smoothing, amplitude contrast, variance, dip illumination, fault likelihood and likewise integrates spectral decomposition by continuous wavelet transform and swarm algorithms to attenuate the random seismic noise, preserve the amplitude discontinuities, smooth the seismic reflectors and highlight the lineal features and finally skeletonize them. Through seismic data conditioning, edge detection and edge enhancement we obtain an ant-tracking volume in which geological faults, their locations, extensions, orientations are more accurately identified and at the same time enables the automatic extraction of fault planes. Additionally, owing to the good definition of the fault planes on the final ant-tracking it is possible to extract the density fracture attribute to identify qualitatively high fracture density zones to be avoided for future wellbore paths. The different seismic attributes and the spectral decomposition were tested by using a seismic volume of an oil field located in the Middle Magdalena Valley basin characterized by a high random noise level and complex geological structures. The final ant-tracking volume mainly distinguishes two fault systems with NW-SE trend: 1. Conjugate normal faults altogether with scissors faults and 2. High angle reverse faults associated with tectonic inversion events. Introduction The new challenges of the oil and gas industry require the development of new techniques and technologies to reduce the risk failure during drilling operations. Using seismic data is possible to analyse the geological configuration of the subsurface. With the development of seismic attributes at the end of the last century, the way in which seismic interpreters elaborate geological models has changed. Seismic attributes reveal characteristics, relations, and patterns of seismic information that cannot be easily perceived (Chopra & Marfurt, 2007). Seismic attributes are tools to infer geology from seismic data (Barnes, 2001). Therefore, they help to solve dissimilar problems associated with the interpretation and characterization of the subsurface geological configuration. For instance, identifying fault patterns and structural styles. Furthermore, they contribute to the mitigation of a certain number of wellbore stability problems such as lost circulation or overpressure, that result in non-productive times and economic effects. Planning the wellbore trajectory to avoid possible areas of fluid losses near faults is a way to prevent lost circulation. These areas could also be related to formations with natural fractures and areas surrounding fault planes where rocks tend to have a brittle behavior. So that, the presence of surrounding fractures allows the circulating fluid to filtrate through the formation, increasing the risk of lost circulation (Lavrov, 2016).

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 In Putumayo basin at south of Colombia is located Loro-Acaé Block in an anticlinal structure lightly folded. Several vertical wells were drilled from 60’s, achieved more than 10 thousand feet; currently, in the new campaign, wells are planned and drilled with high deviation angles (>30°) being a challenge related to wellbore stability in shale rocks of Orteguaza and Villeta formations and wellbore geometry issues in interbedded rocks of Pepino and Rumiyaco formations. Also, gas overpressures are detected in shales and limestones of Villeta formation can overcome 15 ppg increasing the challenge to drill these wells minimizing the risks associates to well kicks, mud cuts, pack offs, stuck pipe and losses. T Sandstone, member of Villeta formation, has the lowest fracture gradient in this formation. Using MW over 14 ppg to control gas and shales stability, a lot of times there were induced fractures in T Sandstone with mud losses and disequilibrium of hydrostatic column become mud cut and gas influx, and then, well control operations. A 3D pore pressure model was developed in Loro-Acaé Block in order to stablish lateral and depth variations in Rumiyaco and Villeta formations. This model is currently being used during well planning to determine risks associated with gas influx, and therefore, establish better well trajectories and adequate mud weight to avoid issues related with gas presence. An attack angle analysis in the well trajectories planning with critical displacements is done as well with the aim of improving the stability of fissile rocks (especially shales). A geomechanics real time monitoring has been done which has allowed avoid and/or mitigate drilling risks related to rock mechanical behaviour: wellbore stability across cavings morphology, rate and size analysis, minimum horizontal stress and fracture initiation gradient as limits of ECD, calculate or change the BHA trip speed, suggested circulation points to well cleaning while tripping, suggested changes in MW according to wellbore stability observed and controlling of casing setting points to isolate formations of different behaviours. The geomechanical analysis plays a fundamental role in this challenge since it allows solving the stress-strain problem in laminated rocks to determine their stability as well as the pore pressure behaviour of the fluids: water, gas and oil. This analysis helps establish the drilling phases, the mud densities to be used and the best well orientation to reach drilling success.

Abstract Sand production in an oil and gas industry is a complex phenomenon causing operational costs to increase drastically, so controlling or managing sand has become very important in reservoir planning and development. During sand production, formation grains or chunks are detached from formation cavities due to mechanical loading processes, then transported to the wellbore by the flowing fluids, either oil, water or gas. This article presents a new model for sand production forecasts, which model couples the fluid flow and geomechanics and includes a sand production relationship. For the mechanical behavior an elastoplastic constitutive model and a sand production relationship is used, meanwhile, the fluid is slightly compressible and monophasic. The sand production relationship states that sand production occurs after high shear plastic strains are accumulated. FEM method is used for the numerical solution of the resulting system. To verify the model’s behavior, results for a hypothetical case are compared with laboratory and previous reported in the literature related with sanding behavior. Among others results, is the relationship between the mechanical loading as a mechanism to promote sanding. Finally, in order to quantify the most important variables in sanding, a sensitivity analysis is performed. This analysis shows the effect of in situ stress state, sanding parameters and cohesion, being, after the sanding parameters, the cohesion as the most important variable for sand produced mass. The presented model has an important potential and its easy applicability positions it as an easy tool for matching and forecasting sand production. Introduction Sand production is found in several reservoirs, commonly in poor or not cemented formations. Among sanding problems are: reduction or cessation of production, damage to the flow equipment either down-hole or in surface. Reason why sand management uses sand risk indicators to work with sanding, but when the risk is high (including economic impacts) then it is required the use of methods for sand control and mitigation. There exist several ways to infer sand production potential such as dimensionless relationships (Bazanti & Desai, 1988), total compressibility to shear modulus ratio (Khamehchi & Reisi, 2015), neural network applications (Kanj & Abousleiman, 1999) and analytical solutions. Unfortunately, these methods do not predict sand production levels which are required to design properly the development plan for a wellbore or reservoir. Numerical models are used to determine with higher detail the forecasts of sand production, and this way a numerical sand production model is presented accounting. The objective of the current work is to evaluate the influence of selected properties in sand produced mass. Ideally, sand production is a coupled problem which involves pressure changes, flow velocities, geomechanical behavior and sanding is a results of this variables changing during different operations.

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 Previous studies show that Lambda-rho/Mu-rho cross plots from seismic data can be used to quantitatively grade unconventional plays. In this work which condenses the results of first author’s M.Sc. thesis, we examine the utility of these cross plots with actual field data acquired from the Lower Barnett play. We use seismically inverted Poisson’s ratio as a fracability discriminator and Young’s modulus as an indicator of Total Organic Carbon (TOC) richness and porosity. We classify the Lower Barnett shale in the study area into four rock groups: Brittle-Rich, Rich-Ductile, Brittle-Poor, and Ductile-Poor. We validate these results using production logs and microseismic data acquired on four wells. Production logs directly measure the rates coming from each perforation cluster while microseismic events directly measure locations where the rock breaks which is a good proxy to the stimulated rock volume, SRV. Integration of seismic data, production logs and microseismic data indicates that Brittle-Rich zones are the most suitable locations to drill wells in this particular play because they exhibit two components: significant hydrocarbon in place and sufficient strength to sustain effective fractures. On the other hand, rock zones characterized as Ductile-Poor should be avoided during drilling and fracturing since once the fracturing pressure is released, the rock will close back against the proppant resulting in ineffective completions. Brittle-poor zones adjacent to zones with high TOC (rich zones) can also be target drilling locations since the brittle/competent rock can sustain long-lasting hydraulic fracture treatments bridging the gap between the hydrocarbon rich zone and the wellbore. Introduction One of the key developments critical to making shale wells economically productive over extended periods of time is the use of hydraulic fracture treatments. In combination with horizontal well technology, shale gas wells are now orders of magnitude more productive than wells completed in similar settings in the 1990s to the early 2000s (Agrawal et al., 2012). Shale wells are now routinely completed with a suite of hydraulic fracture treatments in several stages (Bennett et al., 2006; Bruner and Smosna, 2011). The stages are designed to contact as much of the reservoir rock as possible, thereby creating highly conductive oil and gas migration pathways between the reservoir rock and the wellbore (Daniels et al., 2007; Cipolla et al., 2008; Mayerhofer et al., 2010; Cipolla et al., 2012; Yu and Aguilera, 2012). Additionally, as our knowledge of shales has expanded from the classical homogeneous seal rock model to that of a reservoir rock characterized by considerable lateral and vertical variability, there is an increasing need to exploit this knowledge for optimal well and fracture placement. The work presented in this paper is organized around this main theme: to identify optimal locations for infill drilling and for hydraulic fracture treatments by mapping these heterogeneities and identifying the location and distribution of significant hydrocarbon accumulations to extract shale oil and gas resources more efficiently and economically.

Abstract One of the aspects that impacts wellbore's performance is the ductile behavior that a reservoir-rock can experience when subjected to high evolving compressive effective stresses resulting from depletion. During production, the reservoir-stress path can move within the elastic domain while at the same time, the Near Wellbore (NWB) stress path moves inside the plastic region. Poroelastoplastic deformations induce NWB damages leading to high skin evolution, lowering production, and in some cases forcing well shutins. This paper shows that cumulative stress-strain responses at the reservoir scale level need to be carried onto the near wellbore region to assess properly any productivity or injectivity loss. The goal is to understand better factors affecting NWB performance and provide geomechanical analysis tools to assist interpretation of skin evolution. The analysis shows that reservoir stress paths do not always follow the NWB stress paths. Hence, the NWB region cannot detach its performance from the field scale's response. Results indicate that skin evolution remains associated with pressure fluctuations via permeability changes and, most notably to Volumetric Strain Changes (VSC). This finding allows utilization of volumetric strains as a tracking tool of skin evolution similar to skin monitoring from PTAs. Therefore, it is possible to track skin evolution as an evolution of volumetric strain. Furthermore, VSCs can point out the length and preferential orientations of geomechanical formation damage. As a result, better-inform decisions can be made, for instance, on stimulation type selection, hydraulic fracture impairment, and drawdown pressure limits as part of the wellbore productivity enhancement processes. Introduction It is essential to understand the geomechanical impact of pressure changes in the near-wellbore region; such fluctuations alter the stress state and ultimately the reservoir rock's reaction. Ductile materials exhibit more pronounced effects than brittle rocks, particularly when in situ conditions are such that the wellbore is close to the rock yielding envelopes (Schutjens, P., 2001; Schultz, R., 2005). During production, the reservoir stress path can move within the elastic domain. Simultaneously, the Near Wellbore (NWB) stress path can move inside the plastic region, manifesting as an evolution of wellbore skin. Field observations indicate that NWB damage induced by rock deformations promotes high skin evolution over time, lowering production, and in many cases forcing well shut-ins (Ugoala, O., 2013). The industry faces the need for more applied geomechanics in coupling both reservoir and near wellbore region responses to better understand different field operational issues. For instance, tracking of mechanical skin evolution, estimation of flowing bottom hole pressure limits, completion damage, and induced deformation bands, among others, require geomechanical coupling between the reservoir and the altered zone around wellbores. Based on field observations, this paper illustrates that the stress-strain response at the reservoir-scale level needs to be carried onto the near-wellbore region to assess adequately any productivity loss. After evaluating and discarding all potential causes of skin development, the cases presented here deal with stress-induced wellbore damage related to production as the only root cause of skin evolution.

Abstract This paper proposes a practical and cost-effective procedure to perform a wellbore stability analysis, including the elaboration of a safety mud window and the evaluation of the wellbore trajectory using drilling data (drilling reports, drilling parameters, mud properties, and mud-logging samples) that are routinely gathered in every well. The workflow includes the estimation of the rock geomechanical properties through a back analysis from the drilling parameters and the geomechanical events. These steps comprise the calculation of the pore pressure and stress state using the classical D-exponent method and Eaton's equation, along with the generation of a safety mud window and the evaluation of the wellbore trajectory using the Mohr-Coulomb (MC) failure criteria and the Kirsch's equations. Since the output of the proposed method depends on parameters that are not exactly known, significant engineering criteria and geomechanical expertise are crucial to achieve a quantitative analysis. The proposed approach was evaluated in a study case in a well drilled in the south-west of Colombia. The results were compared to those obtained from a wellbore stability analysis using geomechanical properties estimated from offset well logs, obtaining general agreement in magnitude and trend of the values. These findings suggest that drilling data, when properly used, can provide a reliable wellbore stability analysis for assisting post-drill studies, pre-drill forecasting, and decision making in real-time during the drilling operation. Moreover, the systematic application of the proposed methodology in several wells might allow updating the 3D geomechanical parameters at the reservoir scale. Introduction Wellbore stability analysis has demonstrated to be an important aid for reducing drilling risks and costs related to unwanted drilling events such as loss of circulation, kicks, tight hole, stuck pipe, and hole collapse. The core of a wellbore stability analysis is an accurate one-dimensional mechanical earth model (MEM), whose accuracy is highly affected by the amount of information available for determining the rock geomechanical properties; which are the input parameters of the MEM. Oftentimes, the scarce available information is associated with the high costs of logging, coring, and lab testing programs that in some cases correspond to a large fraction of the total cost of the well; while in other cases, the lack of information is attributed to unsuccessful logging and coring runs in wells with high inclination or instability issues. The use of drilling data for estimating the geomechanical parameters of the drilled formations have been recognized since the 1960s (Cunningham and Eenink, 1959; Combs et al., 1968). A handful of models for estimating the pore pressure from drilling parameters have been proposed (Bourgoyne and Young 1974; Majidi et al. 2017), among these models the more traditional is the D-exponent method (Jorden and Shirley, 1966; Rehm and McClendon, 1971). Despite the theoretical assumptions needed to normalize the rate of penetration (ROP) and the neglect of drilling hydraulics, the D-exponent method is the most widespread in the industry, mainly due to its practicality and the low amount of information required for its implementation.

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 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.

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.

Abstract The Caribbean basin has been a target for hydrocarbon exploration since early 50's, however, due to geological complexity, technological challenges and high cost, drilling activities had been sporadic. Nowadays, Colombia is moving into uncharted territories and the future of the industry is focused in deep and ultra-deep-water exploration. As the water depth increases the operational challenges became more difficult. Low temperatures at the sea bed, presence of methane hydrates, potential shallow gas or water flows, high pressure and high temperature, unconsolidated formations, remote locations with different types of shallow hazards and difficult logistics, extreme weather events, currents and waves, among others factors, create challenging environments to work [1, 9]. Under this challenging conditions, with daily rig costs running around 1 million dollars, the implementation of new technologies to minimize operational risk and make a proper hazard assessment is mandatory. To build geomechanical models is a useful quantitative approach to understand the behavior of the rocks given a state of stresses. Furthermore, an accurate pore pressure and fracture gradient estimation are required to optimizing mud weights, design the casing program and also to assure safety concerns. Pore pressure models in frontier areas are typically estimated using seismic interval velocity fields and then calibrated with real time pressure data from LWD measurements and events observed during drilling operations. All this allow to incorporate, an effective risk and uncertainty management in ultra-deep water environment [2, 3]. This paper describes the integrated Geomechanics workflow applied to complex wells in the ultra-deep water in the Caribbean Basin and describes how an integrated approach in real time can improve drilling operation and minimize risks in remote operating areas.

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: Geomechanical simulations are a powerful tool to forecast caprock deformation and failure behaviour. However, a number of drawbacks associated with simulation are often cited in dissuading their use as a major tool for caprock integrity assessment. This paper will explain that these drawbacks are not inherent in simulation itself. If vigorous efforts are exercised, there are means to overcome these drawbacks. Three approaches are presented: deterministic, probabilistic, and joint inversion. Theoretical principles as well as case histories are given to support observations: forward deterministic simulations are still valid in yielding accurate results that compare well with field observations; probabilistic simulation is a powerful tool to quantify the impact of uncertain material properties and their spatial variability; and the data-intensive nature of a thermal project is an important asset that can be used by a joint mathematical inversion system to make inferences about evolving subsurface processes. 1 INTRODUCTION Whether or not it contains resources of economic value, every interval of subsurface rock formation is invaluable and their integrity must be safeguarded. If containment integrity of the caprock above a petroleum reservoir is damaged, reservoir fluid can escape into undesirable locations. This is particularly essential for heavy-oil development because it requires reservoir stimulation through injection of steam, solvent, and other chemicals to reduce the oil viscosity. For example, cumulative energy injected into a reservoir and thus stored at the subsurface during a thermal project is too significant to ignore the caprock integrity issues. If not managed properly, this energy source can harm us socially, environmentally, and economically. Several incidences of steam release, drilling blowout, reservoir fluid escaping into shallow depths including into groundwater aquifers, or reservoir fluid escaping to the ground surface have been reported publically (Smith et al. 2004; ERCB 2010; AER 2013). More common is the significant casing deformation during thermal operation. Moreover, concerns are raised about the significant uneven surface heave that may alter facilities, roads, landscape, and surface/subsurface hydrogeological conditions. Caprock integrity eventually becomes a geomechanical issue, even though it is first a concern of hydraulic integrity (i.e., no reservoir fluid should escape through the caprock into more shallow areas). Naturally, such hydraulic integrity is already inherently placed in-situ in the geological history because the caprock has prevented any further upward movement of hydrocarbon migration.

SUMMARY: Wellbore instability during drilling cause substantial problems in different areas of the world, even in vertical wells. These problems occur when the near wellbore stress exceed the rock strength. To prevent these problems must establish a balance between stress and the strength of the rock, which must be restored or maintained during drilling through the proper formulation of drilling fluids, mud weights, trajectory of well and drilling practices. Wells drilled in laminated shales or sequences of shale-sand, are classified as more unstable than those drilled in homogeneous and isotropic formations, this because the laminated materials may fail in two ways, first as intact rock where material strength is greater, and the second as sliding bedding planes, where resistance is lower. The way in which the failure of the rock is generated will be strongly influenced by the wellbore trajectory that has the with respect to the planes of weakness of the rock. For the evaluation of the impact that can have the presence of the planes of weakness in the wellbore stability, a numerical modeling with a commercial software called the ABAQUS, which has a constitutive material model called " Joint Material", by which you may include a anisotropy in the rock material modeling, with which it represents the planes of weakness, in resistance and frictional properties. The implementation of this model to determine the mud weight that which the rock failure, either by planes of weakness or intact rock and have the sensitivity of what may be the volume of rock affected under certain conditions of mud weight. This article presents comparison between collapse pressures obtained with analytical methodologies, the influence of the planes of weakness in the geometry of the fault and a field application.

SUMMARY: During the initial evaluation phase of an exploration project in unconventional reservoirs the intervals that will be completed should be prioritized, as a consequence, it is necessary to create a methodology to optimize the selection of intervals for stimulating. This selection is made more difficult at the beginning of the exploratory phase, especially in very thick formations (greater than 500 ft), where there may be several prospective intervals from the point of view of rock quality. Initial tests in vertical wells have a higher investment risk associated with the completion of unfavorable horizons for fracturing, i.e. failures during execution the hydraulic fracturing or great difficulty for proppant admission, therefore an inefficient fracture is created for migration of reservoir fluids into the well. As a result of interdisciplinary work, a methodology for selecting horizons with greater probability of success in hydraulic fracturing (under the Colombian tectonic environment) and for incorporating resources in a vertical well in an unconventional reservoir that has several prospective horizons was generated. Additionally, for the horizons with potential production of gas and gas condensate, a prioritization criterion was established, taking into account the effect of pore pressure decline on the matrix permeability (stress sensitivity). The proposed methodology is based on: generate and interpret an anisotropic geomechanical model, selecting intervals that meet the quality criterion for completion in terms of elastic properties, generate a probabilistic solution for the distribution of the minimal horizontal stress, fracture gradient and net pressure, classifying selected intervals based on the likelihood of having a favorable complexity fracture, classifying the intervals in terms of mobility of fluids in the reservoir, sorting the prospective intervals in terms of value generation associated with each resource. By applying the methodology it is achieved for example discard prospective horizons with good rock quality, high probability of success of completion but low incorporation of resources, another possibility is to discard horizons with good rock quality, good fluid quality but low probability of successful completion. As a result of the exercise the operator managed to prioritize investment in 3 of the 6 prospective horizons for completion and testing.