A Simulator with Numerical Upscaling for the Analysis of Coupled Multiphase Flow and Geomechanics in Heterogeneous and Deformable Porous and Fractured Media

A growing demand for more detailed modeling of subsurface physics as ever more challenging reservoirs - often unconventional, with significant geomechanical particularities - become production targets has moti-vated research in coupled flow and geomechanics. Reservoir rock deforms to given stress conditions, so the simplified approach of using a scalar value of the rock compressibility factor in the fluid mass balance equation to describe the geomechanical system response cannot correctly estimate multi-dimensional rock deformation. A coupled flow and geomechanics model considers flow physics and rock physics simultaneously by cou-pling different types of partial differential equations through primary variables. A number of coupled flow and geomechanics simulators have been developed and applied to describe fluid flow in deformable po-rous media but the majority of these coupled flow and geomechanics simulators have limited capabilities in modeling multiphase flow and geomechanical deformation in a heterogeneous and fractured reservoir. In addition, most simulators do not have the capability to simulate both coarse and fine scale multiphysics. In this study I developed a new, fully implicit multiphysics simulator (TAM-CFGM: Texas A&M Coupled Flow and Geomechanics simulator) that can be applied to simulate a 2D or 3D multiphase flow and rock deformation in a heterogeneous and/or fractured reservoir system. I derived a mixed finite element formu-lation that satisfies local mass conservation and provides a more accurate estimation of the velocity solu-tion in the fluid flow equations. I used a continuous Galerkin formulation to solve the geomechanics equa-tion. These formulations allowed me to use unstructured meshes, a full-tensor permeability, and elastic stiffness. I proposed a numerical upscaling of the permeability and of the elastic stiffness tensors to gener-ate a coarse-scale description of the fine-scale grid in the model, and I implemented the methodology in the simulator. I applied the code I developed to the simulation of the problem of multiphase flow in a fractured tight gas system. As a result, I observed unique phenomena (not reported before) that could not have been deter-mined without coupling. I demonstrated the importance and advantages of using unstructured meshes to effectively and realistically model a reservoir. In particular, high resolution discrete fracture models al-lowed me to obtain more detailed physics that could not be resolved with a structured grid. I performed numerical upscaling of a very heterogeneous geologic model and observed that the coarse-scale numerical solution matched the fine scale reference solution well. As a result, I believed I developed a method that can capture important physics of the fine-scale model with a reasonable computation cost

INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California, through the testing and application of advanced reservoir characterization and thermal production technologies. The hope is that successful application of these technologies will result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs, including: (1) Development of three-dimensional (3-D) deterministic and stochastic reservoir simulation models--thermal or otherwise--to aid in reservoir management of the steamflood and post-steamflood phases and subsequent development work. (2) Development of computerized 3-D visualizations of the geologic and reservoir simulation models to aid reservoir surveillance and operations. (3) Perform detailed studies of the geochemical interactions between the steam and the formation rock and fluids. (4) Testing and proposed application of a novel alkaline-steam well completion technique for the containment of the unconsolidated formation sands and control of fluid entry and injection profiles. (5) Installation of a 2100 ft, 14 inch insulated, steam line beneath a harbor channel to supply steam to an island location. (6) Testing and proposed application of thermal recovery technologies to increase oil production and reserves: (a) Performing pilot tests of cyclic steam injection and production on new horizontal wells. (b) Performing pilot tests of hot water-alternating-steam (WAS) drive in the existing steam drive area to improve thermal efficiency. (7) Perform a pilot steamflood with the four horizontal injectors and producers using a pseudo steam-assisted gravity-drainage (SAGD) process. (8) Advanced reservoir management, through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring and evaluation

Finite-Element Simulation Studies for Consequences of Rock Layers and Weak Interfaces in Unconventional Reservoirs

Unconventional reservoir systems are heterogeneous, thinly layered, and often exhibit strongly contrasting properties between layers. In addition, the interfaces between layers vary in strength (friction and cohesion) and, when weak, they provide preferential directions to rock failure and fluid flow. Traditional rock mechanics modeling for hydraulic fracturing, wellbore stability, stress prediction, and other petroleum-related applications assume homogeneous rocks and welded interfaces. This assumption is hard to reconcile with the strongly layered texture and varied layer composition observed in unconventional rocks. Using the finite element method (FEM), we investigated the consequences of the presence of rock layers and weak interfaces on three different subjects: 1) formation shear stress development, shear slip at interfaces, and wellbore stability; 2) hydraulic fracture height growth; and 3) casing shear impairment. For the first scenario in this work, three different layered rock models were simulated and compared: laterally-homogeneous, laterally-heterogeneous, and strongly laterally-heterogeneous. Results show that localized shear stresses develop along interfaces between layers with contrasting properties and along the wellbore walls. It was also seen that rock shear and slip, along interfaces between layers, may occur when the planes of weakness are pressurized (e.g., during hydraulic fracturing). In the second scenario, we used a range of tensile strength and fluid flow properties at the interfaces between layers, to investigate their impact on vertical propagation of hydraulic fracture. The results show a systematic decrease in fracture height and fracturing fluid efficiency with increasing interface hydraulic conductivity and/or decreasing interface strength. We also propose that fluid viscosity has a strong influence on fluid efficiency as well as fracture height growth. In the third scenario, finite-element simulations were also conducted in a casing-cement- formation system to evaluate casing curvature and plastic deformation caused by formation shear movement occurring with slippage along the weak interface between two distinct rock layers. The results indicate that the abrupt curvature change and the plastic deformation along the casing are generated near the slip surface. We also observe that casing shear at the peak temperature during a single thermal cycle of cyclic steam stimulation induces higher casing plastic deformations

The impact of shale pressure diffusion on 4D seismic interpretation

Shale typically has a low but non-negligible permeability of the order of nanodarcys (recognized an appreciated in production of unconventional resources), which could affect the magnitude and pattern of the pressure in conventional reservoirs over the lifetime of a producing field. The implications of this phenomenon for reservoir monitoring by 4D seismic can be significant, but depend on the geology of the field, the time-lines for production and recovery, and the timing of the seismic surveys. In this PhD thesis I developed an integrated workflow to assess the process of shale pressure diffusion and its elastic implications in the 4D seismic interpretation of four conventional reservoirs (three North Sea case studies and one from West Africa), with different geological settings (shallow marine and turbidites) and production mechanisms. To accomplish that, first, a detailed petrophysical evaluation was performed to characterize the overburden, intra-reservoir and underburden shales. Next, the simulation models were adjusted to activate the shale-related contributions, and then, applying simulator to seismic workflows, 3D and 4D synthetic seismic modelling were performed, for comparison with the observed seismic data and to establish the impact of the shale pressure diffusion in the elastic dynamic behaviour of the reservoir. This work also includes a case study where evaluation of shale pressure diffusion was integrated with geomechanical simulations to assess the propagation of time shifts and time strain in the overburden of a high pressure/high temperature reservoir under compaction, improving the understanding of the distribution and polarity of the observed seismic time strain. Fluid flow simulation results of this work indicate that activation of the shale improves the overall reservoir connectivity, enhancing model prediction (production history matched data). The fit to observed 4D seismic data was improved in all the field applications with a noticeable reduction (up to 6%) in the mismatch (hardening and softening signal distribution) for the models with active shales. In reservoirs where the saturation was very sensitive to changes in pressure, shale activation proved to impact strongly on the breakout and distribution of gas liberated from solution. Overall, this work found that inclusion of shale in the 3D and 4D reservoir seismic modelling can provide valuable insights for the interpretation of the reservoir’s dynamic behaviour and that, under particular conditions such as strong reservoir compartmentalization, shale pressure diffusion could be a significant process in the interpretation of the 4D seismic signature

Flow and transport in fractured geothermal reservoirs on different scales: Linking experiments and numerical models

Die Erdwärme stellt eine wichtige erneuerbare Energiequelle der Zukunft dar, um den Grundbedarf der Menschen an Wärme und Strom zu decken und die Abhängigkeit von fossilen Brennstoffen wie Erdöl und Kohle zu verringern. Die Internationale Energiebehörde schätzt, dass bis zum Jahr 2050 3,5% der weltweiten Energieversorgung durch Geothermie erfolgen können. Die Vorteile der Geothermie liegen dabei in der guten bedarfsabhängigen Regulierbarkeit sowie der uneingeschränkten weltweiten Verfügbarkeit bei gleichzeitig geringem Flächenbedarf. Darüber hinaus ist die Geothermie als eine der wenigen erneuerbaren Energien vollständig grundlastfähig und damit unabhängig von stark wechselnden Umwelteinflüssen, wie Windstärke oder Sonneneinstrahlung. Die größte Herausforderung bei der Geothermie liegt in der Erschließung von Niederenthalpie-Lagerstätten, die in Tiefen von einigen Kilometern liegen. Eine Möglichkeit hierzu stellt die Technologie des Enhanced Geothermal Systems (EGS) dar, die geringdurchlässige Gesteinsschichten eines Reservoirs wirtschaftlich nutzbar macht. Bei EGS werden durch hydraulische Stimulation bestehende natürliche Kluftsysteme erweitert und neue Klüfte geschaffen und so ein effektiver Wärmeaustausch zwischen dem geklüfteten Reservoirgestein und zirkulierenden Fluiden ermöglicht. Bisher gibt es allerdings nur wenige Pilotanlagen, wie z.B. in Soultz-sous-Forêts, Frankreich. Der Nachteil dieser Technologie ist, dass die so entstandenen Klüfte nur einen sehr kleinen Teil des Reservoirvolumens darstellen und sich alle an der Fluidzirkulation beteiligten natürlichen und induzierten Prozesse auf engstem Raum abspielen. Das grundlegende Verständnis der hochlokalisierten physikalischen Prozesse und Wechselwirkungen stellt somit den Schlüsselfaktor für einen erfolgreichen, umweltverträglichen und sicheren Betrieb von EGS dar. Ein besonderes Augenmerk muss auf die gegenseitigen Wechselwirkungen zwischen der Kluft und dem zirkulierenden Fluid sowie dem damit verbundenen Transport von Wärme und gelösten Stoffen gelegt werden. Die Kluftöffnung wird oft vereinfacht als der Abstand zwischen zwei parallelen Platten dargestellt. In Wirklichkeit bestehen die Verbindungen zwischen zwei Bohrungen jedoch aus einem kleinräumigen Netzwerk einzelner Klüfte, die wiederum ein stark veränderliches inneres Porenvolumen aufweisen. Die vorliegende Arbeit trägt zu einem besseren Verständnis der Entstehung und geometrischen Beschaffenheit von bevorzugten Fluidwegsamkeiten in geklüfteten Reservoiren sowie der damit verbundenen Transportprozesse bei. Das übergeordnete Ziel der einzelnen Studien ist eine Verknüpfung experimenteller Untersuchungen mit numerischen Modellen, um die relevanten, teilweise skalenabhängigen physikalischen Prozesse in Klüften zu identifizieren und quantifizieren. In den ersten beiden Studien (Kapitel 4 und 5) werden eine Vielzahl von stochastisch einzigartigen granitähnlichen Kluftgeometrien erstellt. Anschließend werden numerische Modelle entwickelt, um die präferentiellen Fluidpfade und deren Eigenschaften im Klufhohlraum unter geothermie-typischen Strömungsbedingungen und unter Verwendung der komplexen Navier-Stokes-Gleichungen zu quantifizieren. Das Ziel der ersten Studie ist die Quantifizierung von räumlichen Unterschieden zwischen den dreidimensionalen und den vereinfachten zweidimensionalen Kluftmodellen. Ein Vergleich zwischen äquivalenten Modellierungen mittels der Navier-Stokes-Gleichungen und dem lokalen kubischen Gesetz erlaubt eine Vorhersage über die Gültigkeit dieser Vereinfachungen. In Abhängigkeit von Fließund Scherrichtung sowie dem angelegten Druckgradienten bilden sich in allen Klüften Kanäle aus, die einen großen Teil des Volumenstroms umfassen, während im Rest der Kluft nur geringe Anteile an Fluidbewegung zu beobachten sind. Innerhalb dieser Kanäle zeigen beide Fließgesetze eine gute Übereinstimmung sowohl für rein laminare als auch turbulente Strömungen (mit Reynolds-Zahlen deutlich über 1). Außerhalb von Kanälen ergibt sich unabhängig vom Fließregime für die zweidimensionale Vereinfachung eine deutliche Überschätzung des zu erwartenden Volumenstroms. In der zweiten Studie werden die einzelnen Kanäle innerhalb der dreidimensionalen Kluft hinsichtlich ihrer Geometrie sowie Transporteigenschaften quantifiziert. Die Ergebnisse zeigen eine starke Anisotropie hinsichtlich der Fließ- und Scherrichtung. Obwohl eine senkrechte Ausrichtung von Strömung und Scherung zu einem deutlich verbesserten Durchfluss führt, haben die gut ausgebildeten und geraden Kanäle nur eine begrenzte Kontaktfläche mit dem umgebenden Gestein und behindern somit einen effizienten Wärmeaustausch. Anders ist dies bei einer parallelen Ausrichtung von Scherung und Strömung. In diesem Fall sind die Kanäle deutlich weniger ausgeprägt und haben zudem einen stark verlängerten absoluten Fließweg und damit verbundene höhere Kontaktfläche. Die dritte Studie (Kapitel 6) umfasst die Verknüpfung von Triaxialexperimenten, durchgeführt an zwei Sandsteinenderivaten mit steigenden Temperaturund Druckbedingungen, mit numerischen Modellen. Ziel ist eine Vorhersage der hydraulischen und mechanischen Gesteinseigenschaften eines potentiellen Reservoirgesteins. Die Ergebnisse zeigen eine poroelastische Kompaktion des Gesteins sowie anschließende nichtlineare Deformation, welche beide mit numerischen Modellen vorhergesagt werden können. Das Drucker-Prager-Kriterium ermöglicht die Bewertung der kritischen Scherspannung unter Berücksichtigung der drei Hauptspannungen. Die Studie zeigt, dass kleinstskalige Veränderungen, wie die mineralogische Zusammensetzung, zwar die Materialeigenschaften des Gesteins beeinflussen, numerische und analytische Modelle dessen Verhalten dennoch beschreiben können. In der vierten und fünften Studie (Kapitel 7 und 8) werden die kleinskalig gewonnen Erkenntnisse sowie weiterführende Felduntersuchungen dazu genutzt, um ein Modell des großräumigen Strömungsregimes im geklüfteten Reservoir von Soultz-sous-Forêts zu entwickeln. In der vierten Studie wird ein Strukturmodell des Soultz-Reservoirs entwickelt und das Strömungsregime entlang von Klüften zwischen den einzelnen Bohrungen mittels numerischer Modelle bestimmt. Durch die Verknüpfung mit den experimentellen Daten mehrerer Zirkulations- sowie Tracerversuche kann das Strömungsregime in bohrlochfernen Bereichen des Reservoirs quantifiziert werden. Darüber hinaus kann eine geologische Struktur identifiziert werden, die die Bohrungen GPK3 und GPK4 zwar hydraulisch separiert, allerdings störungsparallel eine Anbindung an das Fließregime des Oberrheingrabens herstellt. In der fünften Studie wird auf Grundlage des zuvor entwickelten hydraulischen Modells die Sensitivität der Produktionstemperatur hinsichtlich verschiedener operativer Rahmenbedingungen (Injektionstemperatur und Fließraten) untersucht

Seismic history matching using proxy models

Generally, reservoir simulation is used to predict field performance and analyse uncertainties for assistance in decision making, while history matching is a key step in reservoir simulation, which is a process of model adjustment and simulation runs with different reservoir parameter settings until the differences between simulated data and historical data reach minima. An efficient reservoir simulation model must be the one that can predict reservoir performance and update history matching results continuously by modifying the reservoir model as long as new data become available. However, reservoir simulation can be very time consuming, depending on the complexity of the reservoir model, and history matching is even more computationally expensive, since it requires many simulation runs. Recently, intelligent technology advances in the oil and gas industry, have initiated a new era of big data. As different varieties of data have been integrated to make better decisions, together with the generation of high frequency data streams, a major concern for petroleum engineers is how reservoir simulation should be calibrated in line with the real time data without compromising the simulation time. In the seismic history matching (SHM) workflow this may be a more obvious issue than in the conventional well production history matching. In order to address this problem, many studies have been undertaken. Besides increasing computational power, various types of research have focused on speeding up the reservoir simulation process, especially history matching, by either implementing optimisation algorithms or generating efficient proxy models. Nevertheless, there has not yet been a standard method recognized in reservoir simulation. In this study, a novel method has been proposed as an attempt to investigate the possibility of achieving efficient seismic history matching by data-driven proxy models. This thesis essentially involves detailing background motivations, proxy model building, followed by its testing and application in SHM. Comparisons of proxy models with conventional simulators have been made from different aspects. The objective is mainly focused on examining the capability of the proxy models as a simplification of the conventional physics-based simulators in SHM. According to the simulation results, the feasibility of the combination of proxy models has been proven to be successful and efficient. Importantly, huge amounts of time and effort have been saved in the reservoir simulation process. In addition, it is suggested that other challenges of SHM, such as multi-domain comparison and multi-field communication, could be tackled by using the proxy method

Investigations into Heavy Oil Recovery by Vapour Extraction (VAPEX)

It is anticipated that resources from extra-heavy oils and bitumen may resolve the expected future escalation in oil demand. Such oils are usually recovered by thermal methods, however these can be energy intensive, especially for reservoirs with thin net-pay or those bounded with large aquifers or gas caps. This is primarily due to excessive heat losses. On the other hand, VAPour EXtraction of heavy oil (VAPEX) is a more energy-efficient, economically attractive and pollution-free alternative, especially for these problematic scenarios. Despite all the potential benefits of this process, there are many uncertainties associated with the actual physics of the process. The question as to whether the oil drainage rates are sufficient for the mechanism to be economically feasible for field scale application remains unanswered. Prediction of field scale recovery factors by numerical simulation is challenging since a very fine grid is needed to ensure that the physical diffusion dominates the numerical diffusion and then to model the subsequent gravity drainage. Thus, there is a tendency to rely upon the Butler-Mokrys (1989) analytical equation to estimate oil rates. A further uncertainty in field scale application, which has only been investigated in a few studies, is the impact of geological heterogeneity on the process, since this can influence the solvent-oil dispersive mixing as well as the shape of the solvent chamber. This research first investigated the oil drainage rates with VAPEX by performing a series of laboratory experiments in both homogenous and heterogeneous systems (including layered and single discontinuous shales). All experiments were performed in well-characterized glass bead packs using glycerol and ethanol as analogues of heavy oil and solvent, respectively. The porous medium and fluid properties were measured independently. The experimentally measured rates were compared to the estimates derived from the Butler-Mokrys (1989) analytical model. In addition, numerical simulations were performed to validate whether the physical diffusion boundaries were captured correctly. Our experiments revealed that the Butler-Mokrys analytical model substantially underestimated the drainage rates in all cases, even when the effects of convective dispersion and end-point density difference were factored in. Results from the heterogeneous models further suggested that layering may not reduce VAPEX oil drainage rates significantly. The performance in systems with layers and discontinuous shale barriers, however, was less than in homogenous models with higher or equivalent permeabilities. The numerical simulations, therefore, under-predicted the physical oil drainage rates, although the pattern of solvent-oil distribution was correctly captured. The research was then extended from lab-scale experiments to field-scale numerical investigations, using a fine grid, high resolution model with realistic petro-physical properties. The solvent–oil PVT were based on real field properties. Three key criteria were examined: the oil production rates and the recovery factors that it is possible to achieve; the full range of static parameters influencing VAPEX, and; identification of the most sensitive parameters (i.e. reservoir thickness (h), vertical permeability (kv/kh) and average arithmetic permeability). In addition, we compared the performance of VAPEX against Steam Assisted Gravity Drainage (SAGD). These, field scale numerical simulations revealed that VAPEX oil extraction rates incorporating diffusional mixing alone were insufficient for the mechanism to be feasible. Although incorporating single-well tracer test (SWTT) dispersivities into the numerical simulations significantly improved the recovery rates, they still remained unacceptably low.Open Acces

Ultra-fast screening of stress-sensitive (naturally fractured) reservoirs using flow diagnostics

Quantifying the impact of poro-mechanics on reservoir performance is critical to the sustainable management of subsurface reservoirs containing either hydrocarbons, groundwater, geothermal heat, or being targeted for geological storage of fluids (e.g., CO2 or H2). On the other hand, accounting for poro-mechanical effects in full-field reservoir simulation studies and uncertainty quantification workflows in complex reservoir models is challenging, mainly because exploring and capturing the full range of geological and mechanical uncertainties requires a large number of numerical simulations and is hence computationally intensive. Specifically, the integration of poro-mechanical effects in full-field reservoir simulation studies is still limited, mainly because of the high computational cost. Consequently, poro-mechanical effects are often ignored in reservoir engineering workflows, which may result in inadequate reservoir performance forecasts. This thesis hence develops an alternative approach that couples hydrodynamics using existing flow diagnostics simulations for single- and dual-porosity models with poro mechanics to screen the impact of coupled poro-mechanical processes on reservoir performance. Due to the steady-state nature of the calculations and the effective proposed coupling strategy, these calculations remain computationally efficient while providing first-order approximations of the interplay between poro-mechanics and hydrodynamics, as we demonstrate through a series of case studies. This thesis also introduces a new uncertainty quantification workflow using the proposed poro-mechanical informed flow diagnostics and proxy models. These computationally efficient calculations allow us to quickly screen poro-mechanics and assess a broader range of geological, petrophysical, and mechanical uncertainties to rank, compare, and cluster a large ensemble of models to select representative candidates for more detailed full-physics coupled reservoir simulations.James Watt Scholarshi

Forecasting CO2 Sequestration with Enhanced Oil Recovery

The aim of carbon capture, utilization, and storage (CCUS) is to reduce the amount of CO2 released into the atmosphere and to mitigate its effects on climate change. Over the years, naturally occurring CO2 sources have been utilized in enhanced oil recovery (EOR) projects in the United States. This has presented an opportunity to supplement and gradually replace the high demand for natural CO2 sources with anthropogenic sources. There also exist incentives for operators to become involved in the storage of anthropogenic CO2 within partially depleted reservoirs, in addition to the incremental production oil revenues. These incentives include a wider availability of anthropogenic sources, the reduction of emissions to meet regulatory requirements, tax incentives in some jurisdictions, and favorable public relations. The United States Department of Energy has sponsored several Regional Carbon Sequestration Partnerships (RCSPs) through its Carbon Storage program which have conducted field demonstrations for both EOR and saline aquifer storage. Various research efforts have been made in the area of reservoir characterization, monitoring, verification and accounting, simulation, and risk assessment to ascertain long-term storage potential within the subject storage complex. This book is a collection of lessons learned through the RCSP program within the Southwest Region of the United States. The scope of the book includes site characterization, storage modeling, monitoring verification reporting (MRV), risk assessment and international case studies

Análisis geomecánico para la estabilidad en las labores de desarrollo y producción de la mina Santa Clotilde 7-Chongoyape-Lambayeque

El presente trabajo tiene como propósito realizar un análisis geomecánico para la estabilidad en las labores de desarrollo y producción de la mina santa Clotilde 7-ChongoyapeLambayeque. La investigación surgió de la observación de un problema vinculado con la estabilidad de las rocas en las labores en donde se hace el estudio, para dicha investigación se buscó trabajar con una muestra que son las labores de desarrollo y producción, utilizando como tipo y diseño de investigación, siendo cuantitativa con el diseño no experimental descriptivo transversal. Asimismo, para el recojo de información se utilizaron métodos como es; método de análisis documental y método sistémico siendo las técnicas observación y análisis documental, junto a instrumentos empleados como guía de observación, a las implicadas muestras que se hace el estudio, además, se utilizó el programa Google. Toda esta metodología le da a este informe de investigación el respaldo, sustento y seriedad respectiva. Finalmente, se obtuvo como resultados que en la labor de desarrollo su RQD de 80, con RMR 55 una valorización de 60-41, clase de roca III roca regular, teniendo un Q de Barton de 2.66 y GSI 60, en la labor de producción su RQD 75, con RMR 53 una valorización de 60-41, clase de roca III roca regular, teniendo un Q de Barton de 1.25 y GSI de 55 todos estos resultados se presentan por medio de cálculos, análisis de laboratorio y tablas geomecánicas, cada una con sus respectivos análisis que contribuyeron a comprobar la hipótesis: el análisis geomecánico permitirá determinar la estabilidad en las labores de desarrollo y producción de la mina Santa Clotilde 7 – Chongoyape-Lambayeque, todo este trabajo permitió concluir que el análisis geomecánico, permitió determinar, el grado de estabilidad de las labores, determinando, que las labores son inestables para los diferentes tipos de trabajos que se puedan realizar