Usage of Geomechanically Consistent Fracture Model for Drilling Deviated Wells

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.

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

Geophysics ◽  
2011 ◽  
Vol 76 (6) ◽  
pp. WC167-WC180 ◽  
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.

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

2016 ◽  
Vol 4 (4) ◽  
pp. T485-T496 ◽  
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.

Challenges in modelling of hydraulic fracturing in low-permeability coal seams with complex cleat networks and stress regimes

2019 ◽  
Vol 59 (1) ◽  
pp. 166
Author(s):  
Mohammad Ali Aghighi ◽  
Raymond Johnson Jr. ◽  
Chris Leonardi
Keyword(s):  
Numerical Methods ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Computational Cost ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Low Permeability ◽  
Natural Fractures ◽  
Fracture Development

Improved hydraulic fracturing models can better inform operational decisions regarding production from low-permeability coals and ultimately convert currently classified contingent resources to reserves. Improving current modelling approaches requires identification and investigation of the challenges involved in modelling hydraulic fracture stimulation in complex eastern Australian cases where permeability systems and stress regimes can vary significantly. This study investigated differences among existing and emerging advanced hydraulic fracture models and codes including numerical methods used to model fluid and rock behaviours during treatments; the ability to contextualise structure, behaviour and interaction of natural fractures with the propagating hydraulic fracture (e.g. cleat or natural fracture fabric, discrete fracture networks and pressure-dependent leak-off); and their capabilities in handling simultaneously growing or complex fracture development. One finding is that the new generation of models or codes that fully or partially use particle-based numerical methods are more capable in handling complexities associated with hydraulic stimulation of naturally fractured reservoirs. However, the computational cost and time for these models may cause concerns, particularly when modelling large reservoirs and treatments. Based on these limitations, many of the advanced, industry preferred, commercial hydraulic fracture simulators still choose to incorporate limited complexities with regard to natural fractures or represent them mathematically or implicitly. This investigation also indicates that most emerging models provide better representation of natural fractures, visualisation and integration into workflows for completion or stimulation design.

scholarly journals Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3852 ◽  
Author(s):  
Kiran Nandlal ◽  
Ruud Weijermars
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Test Site ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Midland Basin ◽  
Drained Rock Volume ◽  
The Impact

Hydraulic fracturing for economic production from unconventional reservoirs is subject to many subsurface uncertainties. One such uncertainty is the impact of natural fractures in the vicinity of hydraulic fractures in the reservoir on flow and thus the actual drained rock volume (DRV). We delineate three fundamental processes by which natural fractures can impact flow. Two of these mechanisms are due to the possibility of natural fracture networks to possess (i) enhanced permeability and (ii) enhanced storativity. A systematic approach was used to model the effects of these two mechanisms on flow patterns and drained regions in the reservoir. A third mechanism by which natural fractures may impact reservoir flow is by the reactivation of natural fractures that become extensions of the hydraulic fracture network. The DRV for all three mechanisms can be modeled in flow simulations based on Complex Analysis Methods (CAM), which offer infinite resolution down to a micro-fracture scale, and is thus complementary to numerical simulation methods. In addition to synthetic models, reservoir and natural fracture data from the Hydraulic Fracturing Test Site (Wolfcamp Formation, Midland Basin) were used to determine the real-world impact of natural fractures on drainage patterns in the reservoir. The spatial location and variability in the DRV was more influenced by the natural fracture enhanced permeability than enhanced storativity (related to enhanced porosity). A Carman–Kozeny correlation was used to relate porosity and permeability in the natural fractures. Our study introduces a groundbreaking upscaling procedure for flows with a high number of natural fractures, by combining object-based and flow-based upscaling methods. A key insight is that channeling of flow through natural fractures left undrained areas in the matrix between the fractures. The flow models presented in this study can be implemented to make quick and informed decisions regarding where any undrained volume occurs, which can then be targeted for refracturing. With the method outlined in our study, one can determine the impact and influence of natural fracture sets on the actual drained volume and where the drainage is focused. The DRV analysis of naturally fractured reservoirs will help to better determine the optimum hydraulic fracture design and well spacing to achieve the most efficient recovery rates.

scholarly journals Comparison of Flow Solutions for Naturally Fractured Reservoirs Using Complex Analysis Methods (CAM) and Embedded Discrete Fracture Models (EDFM): Fundamental Design Differences and Improved Scaling Method

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-20
Author(s):  
Aaditya Khanal ◽  
Ruud Weijermars
Keyword(s):  
Complex Analysis ◽  
Fractured Reservoirs ◽  
Fluid Velocity ◽  
Naturally Fractured Reservoirs ◽  
Natural Fractures ◽  
Flow Distortion ◽  
Cubic Equation ◽  
Analysis Methods ◽  
Discrete Fracture ◽  
Fracture Models

The present study compares flow paths in reservoirs with natural fractures, solved with Complex Analysis Methods (CAM), to those solved with Embedded Discrete Fracture Models (EDFM). One aim is to define scaling rules for the strength (flux) of the discrete natural fractures used in CAM models, which was previously theoretically defined based on the expected flow distortion. A major hurdle for quantitative benchmarks of CAM with EDFM results is that each of the two methods accounts for natural fractures with different assumptions and input parameters. For example, EDFM scales the permeability of the natural fractures based on a cubic equation, while CAM uses a flux strength. The results from CAM and EDFM are used to scale the flux strength of the natural fractures and improve the equivalent permeability contrast estimation for CAM. The permeability contrast for CAM is calculated from the ratio of the enhanced velocity inside natural fractures to the unperturbed matrix fluid velocity. A significant advantage of flow and pressure models based on CAM is the high resolution without complex gridding. Particle tracking results are presented for fractures with different hydraulic conductivity ranging from highly permeable to impervious.

After-Closure Analysis To Identify Naturally Fractured Reservoirs

2006 ◽  
Vol 9 (01) ◽  
pp. 50-60 ◽  
Author(s):  
Simon T. Chipperfield
Keyword(s):  
Low Cost ◽  
Fractured Reservoirs ◽  
Theory And Practice ◽  
Naturally Fractured Reservoirs ◽  
Reservoir Quality ◽  
Well Testing ◽  
Natural Fractures ◽  
Reservoir Properties ◽  
Reservoir Volume ◽  
Naturally Fractured

Summary After-closure analysis (ACA) in homogeneous-matrix reservoirs provides a method for extracting critical reservoir information from pre-frac injection tests. This paper extends the theory and practice of ACA to identify the presence of productive natural fractures. Natural fractures are important to identify before conducting a stimulation treatment because their presence may require designs that differ from conventional matrix treatments. Literature shows that naturally fractured reservoirs are very susceptible to formation damage and require stimulation treatments to account for this issue. The historical problem, however, has been to confidently characterize the reservoirs pre-frac in terms of both the reservoir quality and the deliverability mechanism (fractures vs. matrix) before committing to these design specifications. This paper presents the results of a simulator used to analyze the mini-frac after-closure period to identify the presence of natural fractures. The simulation results are distilled into a field implementation methodology for determining the extent of natural fracturing and the formation reservoir quality. This methodology is also applied to a field case study to verify the practicality of the technique. Unlike previous mini-frac-analysis methods, this approach identifies natural fractures that are material to production and allows the engineer to distinguish them from "fissures" that are open only during injection and are not a production mechanism. Introduction Motivation for Identifying Natural Fractures. Identifying the presence of natural fractures is important for a broad range of reasons. On a field scale, realizing the presence of natural fractures can impact reserves estimation, initial well rates, production declines, and planned well locations. With respect to well completions, fractured reservoirs may necessitate a special stimulation approach. Because fractured reservoirs tend to produce from a relatively small reservoir volume (i.e., the fractures), these formations can be highly susceptible to damage (Cippolla et al. 1988). The literature shows that the use of foamed treatments (Cippolla et al. 1988), 100 mesh, and low gel loadings can be used to stimulate these reservoirs effectively. The literature also shows the disastrous results that can arise when damage-prevention steps are not taken (Cippolla et al. 1988). As a result, there is a definite need to identify natural fractures before a stimulation treatment so that the appropriate design decisions can be made. In the past, conventional well testing, such as pressure-buildup tests, has been used for determining the reservoir description. However, these techniques often prove costly both in terms of additional equipment requirements and delays in well on-line dates. In addition, conventional well testing may not be successful in low-permeability reservoirs because these wells may not flow at measurable rates before stimulation. These cost and reservoir limitations have forced the engineer to seek other low-cost methods for determining reservoir properties. One such option for acquiring these data is the use of a mini-frac injection test conducted before a stimulation treatment. The mini-frac analysis techniques available to provide estimates of the formation capacity (kh) and indications of the presence of natural fractures include preclosure and post-closure methods.

scholarly journals Predictive Modelling of Naturally Fractured Reservoirs Using Geomechanics and Flow Simulation

GeoArabia ◽  
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.

scholarly journals Hydraulic-Fracture-Height Growth Under the Combined Influence of Stress Barriers and Natural Fractures

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 302-318 ◽  
Author(s):  
Jixiang Huang ◽  
Joseph P. Morris ◽  
Pengcheng Fu ◽  
Randolph R. Settgast ◽  
Christopher S. Sherman ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Height Growth ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
3D Interaction ◽  
Fracture Height ◽  
Fully Coupled

Summary A fully coupled finite-element/finite-volume code is used to model 3D hydraulically driven fractures under the influence of strong vertical variations in closure stress interacting with natural fractures. Previously unknown 3D interaction mechanisms on fracture-height growth are revealed. Slipping of a natural fracture, triggered by elevated fluid pressure from an intersecting hydraulic fracture, can induce both increases and decreases of normal stress in the minimum-horizontal-stress direction, toward the center and tip of the natural fracture, respectively. Consequently, natural fractures are expected to be able to both encourage and inhibit the progress of hydraulic fractures propagating through stress barriers, depending on the relative locations between the intersecting fractures. Once the hydraulic fracture propagates above the stress barrier through the weakened segment near a favorably located natural fracture, a configuration consisting of two opposing fractures cuts the stress barrier from above and below. The fluid pressure required to break the stress barrier under such opposing-fracture configurations is substantially lower than that required by a fracture penetrating the same barrier from one side. Sensitivity studies of geologic conditions and operational parameters have also been performed to explore the feasibility of controlled fracture height. The interactions between hydraulic fractures, natural fractures, and geologic factors such as stress barriers in three dimensions are shown to be much more complex than in two dimensions. Although it is impossible to exhaust all the possible configurations, the ability of a 3D, fully coupled numerical model to naturally capture these processes is well-demonstrated.

Impact of Complex Fracture Networks on Rate Transient Behavior of Wells in Unconventional Reservoirs Based on Embedded Discrete Fracture Model

2021 ◽  
pp. 1-12
Author(s):  
Jiazheng Qin ◽  
Yingjie Xu ◽  
Yong Tang ◽  
Rui Liang ◽  
Qianhu Zhong ◽  
...  
Keyword(s):  
Flow Regimes ◽  
Natural Fracture ◽  
Fracture Model ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Discrete Fracture Model ◽  
Complex Fracture ◽  
Discrete Fracture ◽  
The Impact

Abstract It has recently been demonstrated that complex fracture networks (CFN) especially activated natural fractures (ANF) play an important role in unconventional reservoir development. However, traditional rate transient analysis (RTA) methods barely investigate the impact of CFN or ANF. Furthermore, the influence of CFN on flow regime is still ambiguous. Failure to consider these effects could lead to misdiagnosis of flow regimes and underestimation of original oil in place (OOIP). A novel numerical RTA method is therefore presented herein to improve the quality of reserves assessment. A new methodology is introduced. Propagating hydraulic fractures (HF) can generate different stress perturbations to allow natural fractures (NF) to fail, forming various ANF pattern. An embedded discrete fracture model (EDFM) of ANF is stochastically generated instead of local grid refinement (LGR) method to overcome the time-intensive computation time. These models are coupled with reservoir models using non-neighboring connections (NNCs). Results show that except for simplified models used in previous studies subjected to traditional concept of stimulated reservoir volume (SRV), in our study, the ANF region has been discussed to emphasis the impact of NF on simulation results. Henceforth, ANF could be only concentrated around the near-wellbore region, and it may also cover the whole simulation area. Obvious distinctions could be viewed for different kinds of ANF on diagnostic plots. Instead of SRV-dominated flow mentioned in previous studies, ANF-dominated flow developed in this work is shown to be more reasonable. Also, new flow regimes such as interference flow inside and outside activated natural fracture flow region (ANFR) are found. In summary, better evaluation of reservoir properties and reserves assessment such as OOIP are achieved based on our proposed model compared with conventional models. The novel RTA method considering CFN presented herein is an easy-to-apply numerical RTA technique that can be applied for reservoir and fracture characterization as well as OOIP assessment.

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