Use of seismic attributes and open-hole log data to characterize production variability in a fractured carbonate play: A case study from Madison County, Texas

2019 ◽  
Vol 7 (1) ◽  
pp. T167-T178
Author(s):  
Courtney Beck ◽  
Anna Khadeeva ◽  
Bhaskar Sarmah ◽  
Trey Kimbell
Keyword(s):  
Natural Fracture ◽  
Good Prediction ◽  
Fracture Density ◽  
Natural Fractures ◽  
Well Performance ◽  
Log Data ◽  
Well Production ◽  
Well Completion ◽  
Madison County ◽  
Fractured Carbonate

Understanding natural fracture systems is key for tight carbonate plays, in which production is dependent on secondary interconnected porosity networks. Locating geographic areas and stratigraphic sections with high natural fracture density and optimizing well locations and perforations to connect these fractures can enhance well performance and asset value. There is substantial production variation in the Cretaceous stacked carbonate play in East Texas, despite similarities in well completion and perforated intervals. Petrophysical property models did not explain the significant variation in well production; therefore, we have developed a multidisciplinary workflow combining seismic and log data with the goal of identifying faulting and natural fractures and understanding their effect on production. We used seismic discontinuity to map faults as the main indicator of presence of fractures. We calibrated triple combo logs with an image log to generate an indicator curve to identify natural fractures. The fracture indicator curve provided a good prediction of where natural fractures may occur, and discontinuity maps revealed a good correlation to well production. Furthermore, we concluded that drilling too closely to large faults negatively impacted production and correlated with increased water production. The workflow developed here can be used to optimize well placement in the stacked carbonate play of Madison County, Texas, and it can be applied to other fractured carbonate reservoirs.

scholarly journals Investigation of the Effect of Natural Fractures on Multiple Shale-Gas Well Performance Using Non-Intrusive EDFM Technology

Energies ◽  
2019 ◽  
Vol 12 (5) ◽  
pp. 932 ◽  
Author(s):  
Wei Yu ◽  
Xiaohu Hu ◽  
Malin Liu ◽  
Weihong Wang
Keyword(s):  
Shale Gas ◽  
History Matching ◽  
Natural Fracture ◽  
Fracture Density ◽  
Natural Fractures ◽  
Well Performance ◽  
Two Phase ◽  
Gas Well ◽  
Discrete Fracture Model ◽  
Well Spacing

The influence of complex natural fractures on multiple shale-gas well performance with varying well spacing is poorly understood. It is difficult to apply the traditional local grid refinement with structured or unstructured gridding techniques to accurately and efficiently handle complex natural fractures. In this study, we introduced a powerful non-intrusive embedded discrete fracture model (EDFM) technology to overcome the limitations of exiting methods. Through this unique technology, complex fracture configurations can be easily and explicitly embedded into structured matrix blocks. We set up a field-scale two-phase reservoir model to history match field production data and predict long-term recovery from Marcellus. The effective fracture properties were determined thorough history matching. In addition, we extended the single-well model to include two horizontal wells with and without including natural fractures. The effects of different numbers of natural fractures on two-well performance with varying well spacing of 200 m, 300 m, and 400 m were examined. The simulation results illustrate that gas productivity almost linearly increases with the number of two-set natural fractures. Furthermore, the difference of well performance between different well spacing increases with an increase in natural fracture density. A larger well spacing is preferred for economically developing the shale-gas reservoirs with a larger natural fracture density. The findings of this study provide key insights into understanding the effect of natural fractures on well performance and well spacing optimization.

Predicting Well Performance in Naturally Fractured Reservoir

2013 ◽  
Author(s):  
Yunsuk Hwang ◽  
Jiajing Lin ◽  
David Schechter ◽  
Ding Zhu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Darcy Flow ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Complex Fracture Network

Multiple hydraulic fracture treatments in reservoirs with natural fractures create complex fracture networks. Predicting well performance in such a complex fracture network system is an extreme challenge. The statistical nature of natural fracture networks changes the flow characteristics from that of a single linear fracture. Simply using single linear fracture models for individual fractures, and then summing the flow from each fracture as the total flow rate for the network could introduce significant error. In this paper we present a semi-analytical model by a source method to estimate well performance in a complex fracture network system. The method simulates complex fracture systems in a more reasonable approach. The natural fracture system we used is fractal discrete fracture network model. We then added multiple dominating hydraulic fractures to the natural fracture system. Each of the hydraulic fractures is connected to the horizontal wellbore, and some of the natural fractures are connected to the hydraulic fractures through the network description. Each fracture, natural or hydraulically induced, is treated as a series of slab sources. The analytical solution of superposed slab sources provides the base of the approach, and the overall flow from each fracture and the effect between the fractures are modeled by applying the superposition principle to all of the fractures. The fluid inside the natural fractures flows into the hydraulic fractures, and the fluid of the hydraulic fracture from both the reservoir and the natural fractures flows to the wellbore. This paper also shows that non-Darcy flow effects have an impact on the performance of fractured horizontal wells. In hydraulic fracture calculation, non-Darcy flow can be treated as the reduction of permeability in the fracture to a considerably smaller effective permeability. The reduction is about 2% to 20%, due to non-Darcy flow that can result in a low rate. The semi-analytical solution presented can be used to efficiently calculate the flow rate of multistage-fractured wells. Examples are used to illustrate the application of the model to evaluate well performance in reservoirs that contain complex fracture networks.

Using geomechanical modeling to quantify the impact of natural fractures on well performance and microseismicity: Application to the Wolfcamp, Permian Basin, Reagan County, Texas

2016 ◽  
Vol 4 (2) ◽  
pp. SE1-SE15 ◽  
Author(s):  
Ahmed Ouenes ◽  
Nicholas M. Umholtz ◽  
Yamina E. Aimene
Keyword(s):  
Empirical Relationship ◽  
Production Performance ◽  
Fault System ◽  
Fracture Density ◽  
Natural Fractures ◽  
Well Performance ◽  
Optimal Position ◽  
Complex Fault ◽  
Quantitative Impact ◽  
The Impact

We have evaluated workflows to quantify the mechanical impact of natural fractures (NFs) on the production performance of hydraulically stimulated stages in shale wells. Variations in fracture orientation and density can enhance or degrade the transport and effectiveness of fracturing fluids. Specifically, we studied the effect of a complex fault splay system on a horizontal Wolfcamp B reservoir well. A general workflow that combines geophysics, geology, and geomechanics (3G) was evaluated and applied to the well. The benefits of the 3G workflow are threefold. First, the quantitative impact of the NFs on the regional stress is provided through the differential horizontal stress variation, which impacts fracturing complexity. Then, the reservoir strain map, validated with microseismic data, gives insights into the stimulated drainage pathways. Finally, the ability of the [Formula: see text] integral to predict poor hydraulic fracturing stages as a function of fracture density along the wellbore or as a function of the energy required to propagate a fracture. Building on the validated 3G workflow, a well placement workflow that takes into account the quantitative impact of NFs on well performance was developed on the sample Wolfcamp well. By comparing the [Formula: see text] integral of the same completion stage in simulations with and without NFs, stages with similar [Formula: see text] integral values in both simulations were identified as those not being affected by the NF network. This allows the workflow to provide the optimal position of a well in the presence of NFs associated with a complex fault system that may produce undesirable water. The result is a validated 3G workflow that provides a geomechanical explanation for an empirical relationship showing that high oil production is achieved within a “Goldilocks” range of natural fracturing.

scholarly journals A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume

2020 ◽  
Vol 10 (8) ◽  
pp. 3333-3345
Author(s):  
Ali Al-Rubaie ◽  
Hisham Khaled Ben Mahmud
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Shear Stresses ◽  
Individual Element ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Naturally Fractured

Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.

High-resolution stratigraphic characterization of natural fracture attributes in the Woodford Shale, Arbuckle Wilderness and US-77D Outcrops, Murray County, Oklahoma

2018 ◽  
Vol 6 (1) ◽  
pp. SC29-SC41 ◽  
Author(s):  
Sayantan Ghosh ◽  
John N. Hooker ◽  
Caleb P. Bontempi ◽  
Roger M. Slatt
Keyword(s):  
Natural Fracture ◽  
Fracture Aperture ◽  
Aperture Size ◽  
Fracture Density ◽  
Area Formula ◽  
Woodford Shale ◽  
Fracture Spacing ◽  
Spacing Ratio ◽  
Fracture Intensity ◽  
Bed Thickness

Natural fracture aperture-size, spacing, and stratigraphic variation in fracture density are factors determining the fluid-flow capacity of low-permeability formations. In this study, several facies were identified in a Woodford Shale complete section. The section was divided into four broad stratigraphic zones based on interbedding of similar facies. Average thicknesses and percentages of brittle and ductile beds in each stratigraphic foot were recorded. Also, five fracture sets were identified. These sets were split into two groups based on their trace exposures. Fracture linear intensity (number of fractures normalized to the scanline length [[Formula: see text]]) values were quantified for brittle and ductile beds. Individual fracture intensity-bed thickness linear equations were derived. These equations, along with the average bed thickness and percentage of brittle and ductile lithologies in each stratigraphic foot, were used to construct a fracture areal density (number of fracture traces normalized to the trace exposure area [[Formula: see text]]) profile. Finally, the fracture opening-displacement size variations, clustering tendencies, and fracture saturation were quantified. Fracture intensity-bed thickness equations predict approximately 1.5–3 times more fractures in the brittle beds compared with ductile beds at any given bed thickness. Parts of zone 2 and almost entire zone 3, located in the upper and middle Woodford, respectively, have high fracture densities and are situated within relatively organic-rich (high-GR) intervals. These intervals may be suitable horizontal well landing targets. All observed fracture cement exhibit a lack of crack-seal texture. Characteristic aperture-size distributions exist, with most apertures in the 0.05–1 mm (0.00016–0.0032 ft) range. In the chert beds, fracture cement is primarily bitumen or silica or both. Fractures in dolomite beds primarily have calcite cement. The average fracture spacing indices (i.e., bed thickness-fracture spacing ratio) in brittle and ductile beds were determined to be 2 and 1.2, respectively. Uniform fracture spacing was observed along all scanlines in the studied beds.

scholarly journals 3D finite-element modeling of effective elastic properties for fracture density and multiscale natural fractures

2021 ◽  
Vol 18 (4) ◽  
pp. 567-582
Author(s):  
Shikai Jian ◽  
Li-Yun Fu ◽  
Chenghao Cao ◽  
Tongcheng Han ◽  
Qizhen Du
Keyword(s):  
Finite Element ◽  
Finite Element Modeling ◽  
Elastic Properties ◽  
Least Square ◽  
P Wave ◽  
Fracture Density ◽  
Equivalent Stiffness ◽  
Natural Fractures ◽  
Effective Elastic Properties ◽  
Element Modeling

Abstract Natural fractures are usually multiscale in size, orientations and distribution, resulting in complex anisotropic characteristics. Analytical methods for quantifying the associated effective elastic properties are based on some assumptions, such as dilute fracture concentration and regular-shaped fractures, which do not occur in actual reservoirs. Here, we conduct anisotropic finite-element modeling of effective elastic properties of complex fractured rocks using the least-square fitting method. The algorithm is developed for a 3D case and validated by classical effective medium theories for models with different fracture densities. The results of the 3D numerical method agree well with the theoretical predictions at low fracture density. The model also considers the interactions among fractures to calculate equivalent stiffness tensors at high fracture density. Three 2D fracture models are simulated to demonstrate the basic behavior of stress interactions and their effect on the overall elasticity under different fracture densities. We applied the developed model to 3D natural fractures built from a real outcrop, and we found that the fracturing pattern significantly affects the effective anisotropy properties. The resultant P-wave phase velocities as functions of the incidence angle and frequency are anisotropic. This study provides a great potential to calculate equivalent stiffness tensors and anisotropic properties of 3D multiscale natural fractures.

The Effect of Well Azimuth or Don't Let Your Landman Plan Your Well Path!

2015 ◽  
Author(s):  
Fen Yang ◽  
Larry K. Britt ◽  
Shari Dunn-Norman
Keyword(s):  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Principal Stresses ◽  
Lateral Direction ◽  
Well Completion ◽  
Stimulation Of

Abstract Since the late 1980's when Maersk published their work on multiple fracturing of horizontal wells in the Dan Field, the use of transverse multiple fractured horizontal wells has become the completion of choice and become the “industry standard” for unconventional and tight oil and tight gas reservoirs. Today approximately sixty percent of all wells drilled in the United States are drilled horizontally and nearly all of them are multiple fractured. Because a horizontal well adds additional cost and complexity to the drilling, completion, and stimulation of the well we need to fully understand anything that affects the cost and complexity. In other words, we need to understand the affects of the principal stresses, both direction and magnitude, on the drilling completion, and stimulation of these wells. However, little work has been done to address and understand the relationship between the principal stresses and the lateral direction. This paper has as its goal to fundamentally address the question, in what direction should I drill my lateral? Do I drill it in the direction of the maximum horizontal stress (longitudinal) or do I drill it in the direction of the minimum horizontal stress (transverse)? The answer to this question relates directly back to the title of this paper and please "Don't let your land man drive that decision." This paper focuses on the horizontal well's lateral direction (longitudinal or transverse fracture orientation) and how that direction influences productivity, reserves, and economics of horizontal wells. Optimization studies using a single phase fully three dimensional numeric simulator including convergent non-Darcy flow were used to highlight the importance of lateral direction as a function of reservoir permeability. These studies, conducted for both oil and gas, are used to identify the point on the permeability continuum where longitudinal wells outperform transverse wells. The simulations compare and contrast the transverse multiple fractured horizontal well to longitudinal wells based on the number of fractures and stages. Further, the effects of lateral length, fracture half-length, and fracture conductivity were investigated to see how these parameters affected the decision over lateral direction in both oil and gas reservoirs. Additionally, how does completion style affect the lateral direction? That is, how does an open hole completion compare to a cased hole completion and should the type of completion affect the decision on in what direction the lateral should be drilled? These simulation results will be used to discuss the various horizontal well completion and stimulation metrics (rate, recovery, and economics) and how the choice of metrics affects the choice of lateral direction. This paper will also show a series of field case studies to illustrate actual field comparisons in both oil and gas reservoirs of longitudinal versus transverse horizontal wells and tie these field examples and results to the numeric simulation study. This work benefits the petroleum industry by: Establishing well performance and economic based criteria as a function of permeability for drilling longitudinal or transverse horizontal wells,Integrating the reservoir objectives and geomechanic limitations into a horizontal well completion and stimulation strategy,Developing well performance and economic objectives for horizontal well direction (transverse versus longitudinal) and highlighting the incremental benefits of various completion and stimulation strategies.

Analytical and Machine-LearningAnalysis of Hydraulic Fracture-Induced Natural Fracture Slip

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Peidong Zhao ◽  
K. E. Gray
Keyword(s):  
Failure Modes ◽  
Statistical Significance ◽  
Frictional Coefficient ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Well Performance ◽  
Stimulated Reservoir Volume ◽  
Relative Angle ◽  
Statistical Measures ◽  
Net Pressure

Summary Stimulated reservoir volume (SRV) is a prime factor controlling well performance in unconventional shale plays. In general, SRV describes the extent of connected conductive fracture networks within the formation. Being a pre-existing weak interface, natural fractures (NFs) are the preferred failure paths. Therefore, the interaction of hydraulic fractures (HFs) and NFs is fundamental to fracture growth in a formation. Field observations of induced fracture systems have suggested complex failure zones occurring in the vicinity of HFs, which makes characterizing the SRV a significant challenge. Thus, this work uses a broad range of subsurface conditions to investigate the near-tip processes and to rank their influences on HF-NF interaction. In this study, a 2D analytical workflow is presented that delineates the potential slip zone (PSZ) induced by a HF. The explicit description of failure modes in the near-tip region explains possible mechanisms of fracture complexity observed in the field. The parametric analysis shows varying influences of HF-NF relative angle, stress state, net pressure, frictional coefficient, and HF length to the NF slip. This work analytically proves that an NF at a 30 ± 5° relative angle to an HF has the highest potential to be reactivated, which dominantly depends on the frictional coefficient of the interface. The spatial extension of the PSZ normal to the HF converges as the fracture propagates away and exhibits asymmetry depending on the relative angle. Then a machine-learning (ML) model [random forest (RF) regression] is built to replicate the physics-based model and statistically investigate parametric influences on NF slips. The ML model finds statistical significance of the predicting features in the order of relative angle between HF and NF, fracture gradient, frictional coefficient of the NF, overpressure index, stress differential, formation depth, and net pressure. The ML result is compared with sensitivity analysis and provides a new perspective on HF-NF interaction using statistical measures. The importance of formation depth on HF-NF interaction is stressed in both the physics-based and data-driven models, thus providing insight for field development of stacked resource plays. The proposed concept of PSZ can be used to measure and compare the intensity of HF-NF interactions at various geological settings.

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.

The Stratigraphy of Pre-Tertiary Economic Basement in South Jambi B Block, South Sumatra Basin

2021 ◽  
Keyword(s):  
Significant Contribution ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Density ◽  
The South ◽  
The North ◽  
Fracture Intensity ◽  
Parent Rocks ◽  
Major Fault ◽  
Essential Function

As one of the most promising plays, the Pre-Tertiary basement play holds a significant contribution to the latest success of exploration efforts in the South Sumatra Basin, which then includes the South Jambi B Block. Yet, the natures of the Pre-Tertiary unit in this block remains unsolved. Lithology variability, spatial irregularity, genetic ambiguity, and different reservoir characteristic are indeterminate subjects in the block are the main focus here. The ultimate goals of this study are to better characterize the unit and gain more understanding in calibrating the remaining potential. Based on this study, The Pre-Tertiary units are mainly originated from layered marine-deltaic sedimentary parent rocks with carbonate, intruded by spotty granite where the concentration of each parent rocks varies at the north, the middle, and southern part. Secondly, both lithology heterogeneity and natural fracture density create distinctive reservoir deliverability at each structure. The storage concept is an essential function of natural fracture intensity and diversity, supported by matrix porosity that varies across a different succession of lithology. Lastly, this study observes that major fault orientation is essential in constructing the fracture network. Evidence from several image logs across the study area concludes that most of the interpreted fractures are oriented subparallel to the major faults. The northern belt area is relatively affected by NW-SE Neogene structure, where the southern area is recognized to be affected by both Neogene compression and pre-existing Paleogene structure.

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