Natural Fracture Systems in CBM Reservoirs of the Lorraine–Saar Coal Basin from the Standpoint of X-ray Computer Tomography

The Lorraine–Saar Basin is one of the largest geologically and commercially important Paleozoic coal-bearing basins in Western Europe and has considerable coal reserves in numerous coal beds. The basin stands out due to its sedimentary column of up to 6 km and its inversion, resulting in Paleozoic low-amplitude erosion at around 750 m (French part of the basin) and pre-Mesozoic (Permian) erosion between 1800 and 3000 m (the Saar coalfield or German part of the basin). Thermal maturation of organic matter in sedimentary clastic rocks and coal seams has led to the formation of prolific coalbed methane (CBM) plays in many domains throughout the Carboniferous Westphalian and Stephanian sequences. Coal mines here are no longer operated to produce coal; however, methane generated in “dry gas window” compartments at a depth exceeding 3.5 km has escaped here via several major faults and fracture corridors forming “sweet spot” sites. Faults and a dense network of tectonic fractures together with post-mining subsidence effects also increased the permeability of massive coal-bearing and provided pathways for the breathing of environmentally hazardous mine gases. Nearly all CBM plays can be classified as naturally fractured reservoirs. The Lorraine–Saar Basin is not excluded, indeed, because of the experience of geological surveys during extensive coal-mining in the past. The knowledge of geometrical features of fracture patterns is a crucial parameter for determining the absolute permeability of a resource play, its kinematics environment, and further reservoir simulation. The main focus of this contribution is to gain an insight into the style and structural trends of natural cleat patterns in the basin based on the results of X-ray computer tomography (CT) to ensure technical decisions for efficient exploration of CBM reservoirs. To explore the architecture of solid coal samples, we used X-ray CT of a coal specimen collected from Westphalian D coal from exploratory well Tritteling 1. The studied coal specimen and its subvolumes were inspected in three series of experiments. At different levels of CT resolutions, we identified two quasi-orthogonal cleat systems including a smooth-sided face cleat of tensile origin and a curvilinear shearing butt cleat. The inferred cleat patterns possess features of self-similarity and align with directional stresses. Results of the treatment of obtained cleat patterns in terms of their connectivity relationship allowed the presence of interconnected cleat arrays to be distinguished within studied samples, potentially facilitating success in CBM extraction projects.

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Usage of Geomechanically Consistent Fracture Model for Drilling Deviated Wells

10.2118/206559-ms ◽

2021 ◽

Author(s):

Nikita Vladislavovich Dubinya ◽

Sergey Andreevich Tikhotskiy ◽

Sergey Vladimirovich Fomichev ◽

Sergey Vladimirovich Golovin

Keyword(s):

Optimal Trajectory ◽

Fractured Reservoirs ◽

Fluid Pressure ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Fracture Model ◽

Drilling Process ◽

Natural Fractures ◽

Drilling Parameters ◽

Deviated Wells

Abstract The paper presents an algorithm for the search of the optimal frilling trajectory for a deviated well which is applicable for development of naturally fractured reservoirs. Criterion for identifying the optimal trajectory is the feature of the current study – optimal trajectory is chosen from the perspective of maximizing the positive effect related to activation of natural fractures in well surrounding rock masses caused by changes of the rocks stress-strain state due to drilling process. Drilling of a deviated well is shown to lead to the process of natural fractures in the vicinity of the well becoming hydraulically conductive due to drilling. The paper investigates the main natural factors – tectonic stresses and fluid pressure – and drilling parameters – drilling trajectory and mud pressure – influencing the number and variety of natural fractures being activated due to drilling process. An algorithm of finding the optimal drilling parameters from the perspective of natural fractures activation is proposed as well. Different theoretical scenarios are considered to formulate the general recommendations on drilling trajectory choice according to estimations of stress state of the reservoir. These estimations can be provided based on results of three- and four-dimensional geomechanical modeling. Such modeling may be completed as well for constructing geomechanically consistent natural fracture model which can be used to optimize drilling trajectories during exploration and development of certain objects. The paper presents a detailed algorithm of constructing such fracture models and deviated wells trajectories optimization. The results presented in the paper and given recommendations may be used to enhance drilling efficiency for reservoirs characterized by considerable contribution of natural fractures into filtration processes.

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Predictive Modelling of Naturally Fractured Reservoirs Using Geomechanics and Flow Simulation

GeoArabia ◽

10.2113/geoarabia060127 ◽

2001 ◽

Vol 6 (1) ◽

pp. 27-42

Author(s):

Stephen J. Bourne ◽

Lex Rijkels ◽

Ben J. Stephenson ◽

Emanuel J.M. Willemse

Keyword(s):

Fractured Reservoirs ◽

Flow Simulation ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Production Data ◽

Well Test ◽

Fracture Networks ◽

Field Scale ◽

Fracture Permeability ◽

Naturally Fractured

ABSTRACT To optimise recovery in naturally fractured reservoirs, the field-scale distribution of fracture properties must be understood and quantified. We present a method to systematically predict the spatial distribution of natural fractures related to faulting and their effect on flow simulations. This approach yields field-scale models for the geometry and permeability of connected fracture networks. These are calibrated by geological, well test and field production data to constrain the distributions of fractures within the inter-well space. First, we calculate the stress distribution at the time of fracturing using the present-day structural reservoir geometry. This calculation is based on a geomechanical model of rock deformation that represents faults as frictionless surfaces within an isotropic homogeneous linear elastic medium. Second, the calculated stress field is used to govern the simulated growth of fracture networks. Finally, the fractures are upscaled dynamically by simulating flow through the discrete fracture network per grid block, enabling field-scale multi-phase reservoir simulation. Uncertainties associated with these predictions are considerably reduced as the model is constrained and validated by seismic, borehole, well test and production data. This approach is able to predict physically and geologically realistic fracture networks. Its successful application to outcrops and reservoirs demonstrates that there is a high degree of predictability in the properties of natural fracture networks. In cases of limited data, field-wide heterogeneity in fracture permeability can be modelled without the need for field-wide well coverage.

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Numerical modeling of seismicity induced by fluid injection in naturally fractured reservoirs

Geophysics ◽

10.1190/geo2011-0025.1 ◽

2011 ◽

Vol 76 (6) ◽

pp. WC167-WC180 ◽

Cited By ~ 45

Author(s):

Xueping Zhao ◽

R. Paul Young

Keyword(s):

Numerical Modeling ◽

Fractured Reservoirs ◽

Seismic Source ◽

Microseismic Monitoring ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Hydraulic Fractures ◽

Field Observations ◽

Natural Fractures ◽

Naturally Fractured

The interaction between hydraulic and natural fractures is of great interest for the energy resource industry because natural fractures can significantly influence the overall geometry and effectiveness of hydraulic fractures. Microseismic monitoring provides a unique tool to monitor the evolution of fracturing around the treated rock reservoir, and seismic source mechanisms can yield information about the nature of deformation. We performed a numerical modeling study using a 2D distinct-element particle flow code ([Formula: see text]) to simulate realistic conditions and increase understanding of fracturing mechanisms in naturally fractured reservoirs, through comparisons with results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully dynamic and hydromechanical coupling was used to examine the interaction between natural and induced fractures, the effect of orientation of a preexisting fracture, the influence of differential stress, and the relationship between the fluid front, fracture tip, and induced seismicity. The numerical results qualitatively agree with the laboratory and field observations, and suggest possible mechanics for new fracture development and their interaction with a natural fracture (e.g., a tectonic fault). Therefore, the tested model could help in investigating the potential extent of induced fracturing in naturally fractured reservoirs, and in interpreting microseismic monitoring results to assess the effectiveness of a hydraulic fracturing project.

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Simulation of Hydraulic Fracturing Using Different Mesh Types Based on Zero Thickness Cohesive Element

Processes ◽

10.3390/pr8020189 ◽

2020 ◽

Vol 8 (2) ◽

pp. 189

Author(s):

Chen ◽

Li ◽

Wu ◽

Kang

Keyword(s):

Hydraulic Fracturing ◽

Pore Pressure ◽

Fractured Reservoirs ◽

Fracture Initiation ◽

Fluid Simulation ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Petroleum Engineering ◽

Contact Friction ◽

Triangle Mesh

Hydraulic fracturing is a significant technique in petroleum engineering to enhance the production of shale gas or shale oil reservoir. The process of hydraulic fracturing is extremely complicated, referring to the deformation of solid formation, fluid flowing in the crack channel, and coupling the solid with fluid. Simulation of hydraulic fracturing and understanding the course of the mechanism is still a challenging task. In this study, two hydraulic fracturing models, including the Khristianovic–Geertsma–de Klerk (KGD) problem and the hydraulic fracture (HF) intersection with the natural fracture (NF), based on the zero thickness pore pressure cohesive zone (PPCZ) element with contact friction is established. The element can be embedded into the edges of other elements to simulate the fracture initiation and propagation. However, the mesh type of the elements near the PPCZ element has influences on the accuracy and propagation profile. Three common types of mesh, triangle mesh, quadrangle mesh, and deformed quadrangle mesh, are all investigated in this paper. In addition, the infinite boundary condition (IBC) is also discussed in these models. Simulation indicates that the results of pore pressure for zero toughness regime simulated by the triangle mesh are much lower than any others at the early injection time. Secondly, the problem of hydraulic fracturing should be better used with the infinite boundary element (IBE). Moreover, suggestions for crack intersection on the proper mesh type are also given. The conclusions included in this article can be beneficial to research further naturally fractured reservoirs.

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Volumetric Source Model to Predict Productivity of Fractured Horizontal Well in Naturally Fractured Reservoirs

The Open Petroleum Engineering Journal ◽

10.2174/1874834101508010373 ◽

2015 ◽

Vol 8 (1) ◽

pp. 373-384 ◽

Cited By ~ 2

Author(s):

Tianhui Wang ◽

Haitao Li ◽

Junchao Wang ◽

Yunlin Jia ◽

Lifeng Liu

Keyword(s):

Horizontal Well ◽

Fractured Reservoirs ◽

Source Model ◽

Naturally Fractured Reservoirs ◽

X Ray Diffraction ◽

Cyclic Voltammetric ◽

X Ray ◽

Trigonal Bipyramidal ◽

Fractured Horizontal Well ◽

Square Planar

A novel dinuclear Cu(II) complex material has been synthesized by the reaction of 1, 2-phenylenedioxydiacetic acid, 1,10-phenantroline (phen) and Cu(CHCOO)·HO. And it has been characterized by elemental analysis, IR, UV and single crystal X-ray diffraction. The crystal belongs to tetragonal, space group I4/ with = = 25.381(4) Å, = 32.044(6) Å, = 20643(6) Å, = 16, D= 1.395 g·cm, = 0.898 mm, (000) = 8896, and final = 0.1026, = 0.3142. The structural analysis shows that two Cu(II) atoms adopt different coordination modes, Cu has five-coordination with a trigonal bipyramidal configuration, and Cu has four-coordination with a distorted square planar configuration. The cyclic voltammetric behaviour of the dinuclear Cu(II) complex has been investigated.

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Scale discrepancy paradox between observation and modelling in fractured reservoir models in oil and gas industry.

10.5194/egusphere-egu2020-20161 ◽

2020 ◽

Author(s):

Pascal Richard ◽

Loïc Bazalgette

Keyword(s):

Oil And Gas ◽

Dynamic Models ◽

Fractured Reservoirs ◽

Research Work ◽

Oil And Gas Industry ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Fractured Reservoir ◽

Dynamic Data ◽

Gas Industry

Naturally fractured reservoirs represent one of the most challenging resource in the oil and gas industry. The understanding based on centimeter scale observations is upscaled and modeled at 100-meter scale.In this paper, we will illustrate with case study examples of conceptual fracture model elaborated using static and dynamic data, the disconnect between the scale of observation and the scale of modelling. We will also discuss the potential disconnect between the detail of fundamental, but necessary, research work in universities against the coarse resolution of the models built in the oil industry, and how we can benefit of the differences in scales and approaches.&#160;The appraisal and development of fractured reservoirs offer challenges due to the variations in reservoir quality and natural fracture distribution. Typically, the presence of open, connected fractures is one of the key elements to achieve a successful development. Fracture modelling studies are carried out routinely to support both appraisal and development strategies of these fractured reservoirs.Overall fracture modelling workflow consists first of a fracture characterization phase concentrating on the understanding of the deformation history and the evaluation of the nature, type and distribution of the fractures; secondly of a fracture modelling part where fracture properties for the dynamic simulation are generated and calibrated against dynamic data. The pillar of the studies is the creation of 3D conceptual fracture diagrams/concepts which summarize both the understanding and the uncertainty of the fracture network of interest. These conceptual diagrams rely on detailed observations at the scale of the wellbore using core and borehole image data which are on contrasting scale compare to the 10&#8217;s of meters to 100&#8217;s of meter scale of the grid cells of the dynamic models used for the production history match and forecast. These contrasting scales will be the thread of the presentation.

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Optimization-Based Unstructured Meshing Algorithms for Simulation of Hydraulically and Naturally Fractured Reservoirs With Variable Distribution of Fracture Aperture, Spacing, Length, and Strike

SPE Reservoir Evaluation & Engineering ◽

10.2118/170703-pa ◽

2015 ◽

Vol 18 (04) ◽

pp. 463-480 ◽

Cited By ~ 48

Author(s):

Jianlei Sun ◽

David Schechter

Keyword(s):

Fractured Reservoirs ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Fracture Networks ◽

Complex Fracture ◽

Naturally Fractured ◽

Unstructured Meshing ◽

Domain Discretization ◽

Aperture Distribution ◽

Spacing Length

Summary Multistage hydraulically fractured wells are applied widely to produce unconventional resource plays. In naturally fractured reservoirs, hydraulic-fracture treatments may induce complex-fracture geometries that one cannot model accurately and efficiently with Cartesian and corner-point grid systems or standard dual-porosity approaches. The interaction of hydraulic and naturally occurring fractures almost certainly plays a role in ultimate well and reservoir performance. Current simulation models are unable to capture the complexity of this interaction. Generally speaking, our ability to detect and characterize fracture systems is far beyond our capability of modeling complex natural-fracture systems. To evaluate production performance in these complex settings with numerical simulation, fracture networks require advanced meshing and domain-discretization techniques. This paper investigates these issues by developing natural-fracture networks with fractal-based techniques. After a fracture network is developed, we demonstrate the feasibility of gridding complex natural-fracture behavior with optimization-based unstructured meshing algorithms. Then we can demonstrate that one can simulate natural-fracture complexities such as variable aperture, spacing, length, and strike. This new approach is a significant step beyond the current method of dual-porosity simulation that essentially negates the sophisticated level of fracture characterization pursued by many operators. We use currently established code for fractal discrete-fracture-network (FDFN) models to build realizations of naturally fractured reservoirs in terms of stochastic fracture networks. From outcrop, image-log, and core analysis, it is possible to extract fracture fractal parameters pertaining to aperture, spacing, and length distribution, including center distribution as well as a fracture strike. Then these parameters are used as input variables for the FDFN code to generate multiple realizations of fracture networks mimicking fracture clustering and randomly distributed natural fractures. After incorporating hydraulic fractures, complex-fracture networks are obtained for further reservoir-domain discretization. To discretize the complex-fracture networks, a new mesh-generation approach is developed to conform to nonorthogonal and low-angle intersections of extensively clustered discrete-fracture networks with nonuniform aperture distribution. Optimization algorithms are adopted to reduce highly skewed cells, and to ensure good mesh quality around fracture tips, intersections, and regions of extensive fracture clustering. Moreover, local grid refinement is implemented with a predefined distance function to control cell sizes and shapes around and far away from fractures. Natural-fracture spacing, length, strike, and aperture distribution are explicitly gridded, thus introducing a new simulation approach that is far superior to dual-porosity simulation. Finally, initial sensitivity studies are performed to demonstrate both the capability of the optimization-based unstructured meshing algorithms, and the effect of aforementioned natural-fracture parameters on well performance. This study demonstrates how to incorporate a fractal-based characterization approach into the current work flow for simulating unconventional reservoirs, and most importantly solves several issues such as nonorthogonal intersections, extensive clustering, and nonuniform aperture distribution associated with domain discretization with unstructured grids for complex-fracture networks. The proposed meshing techniques for complex fracture networks can be easily implemented in existing preprocessing, unstructured mesh generators. The sensitivity study and the simulation runs demonstrate the importance of fracture characterization as well as uncertainties associated with naturally fractured reservoirs on well-production performance.

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An integrated modeling approach for natural fractures and posttreatment fracturing analysis: A case study

Interpretation ◽

10.1190/int-2016-0016.1 ◽

2016 ◽

Vol 4 (4) ◽

pp. T485-T496 ◽

Cited By ~ 1

Author(s):

Ping Puyang ◽

Arash Dahi Taleghani ◽

Bhaba Sarker

Keyword(s):

Numerical Models ◽

Fractured Reservoirs ◽

Fracture Network ◽

Integrated Modeling ◽

Naturally Fractured Reservoirs ◽

Natural Fracture ◽

Well Testing ◽

Natural Fractures ◽

Modeling Approach ◽

Treatment Data

Hydraulic fracturing has been the principal production enhancement technique in low-permeability reservoirs for the past few decades. Through core and outcrop studies, advanced logging tools, microseismic mapping and well testing analysis, the complexity of induced fracture network in the presence of natural fractures has been further elucidated. Although most natural fractures are cemented by precipitations due to diagenesis, they can be reactivated during fracturing treatments and serve as preferential paths for fracture growth and fluid flow. However, current technologies for posttreatment fracture analysis are incapable of accurately determining the induced fracture geometry or estimating the distribution of preexisting natural fractures. Despite significant advances in the numerical modeling of fractured reservoirs, those numerical models require detailed characterization of natural fractures, which is essentially impossible to obtain. Moreover, most modeling techniques could not incorporate posttreatment data to reflect actual reservoir characteristics. We have developed an integrated modeling workflow to estimate the actual characteristics of fracture populations based on formation evaluations, microseismic data, treatment data, and production history. A least-squares modeling approach is first used to define possible realizations of natural fractures from selected double-couple microseismic events. Forward modeling incorporating a discrete fracture network will subsequently be used for matching treatment data and screening generated fracture realizations. Reservoir simulation tools will also be used thereafter to match the production data to further evaluate the fitness of natural fracture realizations. Our workflow is able to integrate data from multiple aspects of the reservoir development process, and the results from this workflow will provide geologist and reservoir engineers a robust tool for modeling naturally fractured reservoirs.

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Tensor Analysis of the Relative Permeability in Naturally Fractured Reservoirs

SPE Journal ◽

10.2118/197064-pa ◽

2019 ◽

Vol 25 (01) ◽

pp. 162-184

Author(s):

Mohammad H. Sedaghat ◽

Siroos Azizmohammadi ◽

Stephan K. Matthäi

Keyword(s):

Relative Permeability ◽

Fractured Reservoirs ◽

Naturally Fractured Reservoirs ◽

Permeability Tensor ◽

Absolute Permeability ◽

Scalar Quantity ◽

In Situ Conditions ◽

Discrete Fracture ◽

Naturally Fractured ◽

The Absolute

Summary Fluid evidence shows that prediction of water breakthrough and oil recovery from fractured reservoirs cannot be performed accurately without upscaled relative permeability functions. Relative permeability is commonly assumed to be a scalar quantity, although the justification of that—specifically for naturally fractured reservoirs (NFRs)—is rarely attempted. In this study, we investigate the validity of this scalar-quantity assumption and how it affects fracture/matrix equivalent relative permeabilities, kri(Sw), achieved by a numerical simulation of unsteady-state waterflooding of discrete-fracture/matrix models (DFMs). Numerical determination of relative permeability requires a realistic model, a spatially adaptive simulation approach, and a sophisticated analysis procedure. To fulfil these requirements, we apply the discrete-fracture/matrix modeling to well-characterized outcrop analogs at the hectometer to kilometer scale. These models are parameterized with aperture and capillary entry pressure data, taking into account variations from fracture segment to segment, trying to emulate in-situ conditions. The finite-element-centered finite-volume method is used to simulate two-phase flow in the fractured rock, while also considering a range of wettability conditions from water-wet to oil-wet. Our results indicate that the fracture/matrix equivalent relative permeability is a weakly anisotropic property. The tensors are not necessarily symmetric, and the absolute-permeability tensor is the most influential factor, determining the level of anisotropy of kri. The anisotropy ratio (AR) changes with saturation, is influenced by the fracture/matrix-interface wetted area (Awf), and differs for each phase. In addition, the diagonal terms of the equivalent relative permeability tensor (krii), determined using our novel approach, can be different from those obtained using the assumption that kri is scalar. The magnitude of the difference is controlled by the absolute permeability, wettability, flow rate, and orientation of the fractures in the model. It is worth mentioning that the type and direction of imbibition can be determined by off-diagonal terms of the kri tensor. Furthermore, krii largely depends on the direction of the waterflood along the i-axis.

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