A Novel Approach to Reservoir Simulation of Hydraulic Fractures: Performance Improvement Using Pseudo Well Connections

2022 ◽  
Author(s):  
Aamir Lokhandwala ◽  
Vaibhav Joshi ◽  
Ankit Dutt
Keyword(s):  
Reservoir Simulation ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Time Frame ◽  
Simulation Software ◽  
Hydraulic Fractures ◽  
Current Case ◽  
Future Production ◽  
Novel Approach ◽  
Simulation Problem

Abstract Reservoir simulation is used in most modern reservoir studies to predict future production of oil and gas, and to plan the development of the reservoir. The number of hydraulically fractured wells has risen drastically in recent years due to the increase in production in unconventional reservoirs. Gone are the days of using simple analytic techniques to forecast the production of a hydraulic fracture in a vertical well, and the need to be able to model multiple hydraulic fractures in many stages over long horizontals is now a common practice. The type of simulation approach chosen depends on many factors and is study specific. Pseudo well connection approach was preferred in the current case. Due to the nature of the reservoir simulation problem, a decision needs to be made to determine which hydraulic fracture modeling method might be most suitable for any given study. To do this, a selection of methods is chosen based on what is available at hand, and what is commonly used in various reservoir simulation software packages. The pseudo well connection method, which models hydraulic fractures as uniform conductivity rectangular fractures was utilized for a field of interest referred to as Field A in this paper. Such an assumption of the nature of the hydraulic fracture is common in most modern tools. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The pseudo well connection approach was found to be efficient both terms of replicating data of Field A for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

scholarly journals Analysis of hydraulic fracture behavior and well pattern optimization in anisotropic coal reservoirs

2020 ◽  
pp. 014459872096083
Author(s):  
Yulong Liu ◽  
Dazhen Tang ◽  
Hao Xu ◽  
Wei Hou ◽  
Xia Yan
Keyword(s):  
Hydraulic Fracture ◽  
Coalbed Methane ◽  
Fracture Network ◽  
Simulation Software ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Pattern ◽  
Well Pattern Optimization ◽  
The Impact

Macrolithotypes control the pore-fracture distribution heterogeneity in coal, which impacts stimulation via hydrofracturing and coalbed methane (CBM) production in the reservoir. Here, the hydraulic fracture was evaluated using the microseismic signal behavior for each macrolithotype with microfracture imaging technology, and the impact of the macrolithotype on hydraulic fracture initiation and propagation was investigated systematically. The result showed that the propagation types of hydraulic fractures are controlled by the macrolithotype. Due to the well-developed natural fracture network, the fracture in the bright coal is more likely to form the “complex fracture network”, and the “simple” case often happens in the dull coal. The hydraulic fracture differences are likely to impact the permeability pathways and the well productivity appears to vary when developing different coal macrolithtypes. Thus, considering the difference of hydraulic fracture and permeability, the CBM productivity characteristics controlled by coal petrology were simulated by numerical simulation software, and the rationality of well pattern optimization factors for each coal macrolithotype was demonstrated. The results showed the square well pattern is more suitable for dull coal and semi-dull coal with undeveloped natural fractures, while diamond and rectangular well pattern is more suitable for semi-bright coal and bright coal with more developed natural fractures and more complex fracturing fracture network; the optimum wells spacing of bright coal and semi-bright coal is 300 m and 250 m, while that of semi-dull coal and dull coal is just 200 m.

Time-Dependent Initiation of Multiple Hydraulic Fractures in a Formation With Varying Stresses and Strength

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1317-1325 ◽  
Author(s):  
Andrew P. Bunger ◽  
Guanyi Lu
Keyword(s):  
Tensile Strength ◽  
Hydraulic Fracture ◽  
Fracture Initiation ◽  
Time Frame ◽  
Hydraulic Fractures ◽  
Static Fatigue ◽  
Breakdown Pressure ◽  
Initiation Point ◽  
Delayed Failure ◽  
Wellbore Pressure

Summary The premise of classical hydraulic-fracture-breakdown models is that hydraulic-fracture growth can only start when the wellbore pressure reaches a critical value that is sufficient to overcome the tensile strength of the rock. However, rocks are well-known to exhibit static fatigue; that is, delayed failure at stresses less than the tensile strength. In this paper, we explore the consequences of delayed failure on axially oriented initiation of multiple hydraulic fractures. Specifically, given a certain breakdown pressure, we investigate the conditions under which subsequent hydraulic fracture(s) can begin within the time frame of a stimulation treatment in regions of higher stress and/or strength because of delayed-failure mechanisms. The results show that wells completed in shallower formations are more sensitive to variations in strength, whereas wells completed in deeper formations are more sensitive to variations in stress. Furthermore, cases in which all hydraulic fractures break down according to the same pressurization regime—that is, all are “fast” (nonfluid-penetrating) pressurization or else all are “slow” (uniformly pressurized fluid-penetrating) pressurization cases—are highly sensitive to small stress/strength variability. On the other hand, if the first hydraulic-fracture initiation is in the “fast”-pressurization regime and subsequent fracture(s) are in the “slow”-pressurization regime, then the system is robust to a much-higher degree of variability in stress/strength. Practically, this work implies that methods aimed at moderately reducing the variability in stress/strength among the possible initiation points (i.e., perforation clusters) within a particular stage can have a strong effect on whether multiple hydraulic fractures will begin. In addition, this analysis implies that pumping strategies that encourage “fast,” nonpenetrative breakdown of the first initiation point followed by the opportunity for fluid-penetrating, “slow” breakdown of subsequent initiation points could be effective at encouraging multiple-hydraulic-fracture initiation.

A Case Study of Vertical Hydraulic Fracture Growth, Stress Variations with Depth and Shear Stimulation in the Niobrara Shale and Codell Sand, DJ Basin, Colorado

2021 ◽  
pp. 1-34
Author(s):  
Kevin L. McCormack ◽  
Mark D. Zoback ◽  
Wenhuan Kuang
Keyword(s):  
Principal Stress ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Velocity Model ◽  
Growth Stress ◽  
Hydraulic Fractures ◽  
Stress Profile ◽  
Microseismic Events ◽  
Stress Variations ◽  
Fracture Growth

We carried out a geomechanical study of three wells, one each in the Niobrara A, Niobrara C and Codell sandstone to investigate how the state of stress and stress variations with depth affect vertical hydraulic fracture growth and shear stimulation of pre-existing fractures. We demonstrate that the higher magnitudes of measured least principal stress values in the Niobrara A and C shales are the result of viscoplastic stress relaxation. Using a density log and a VTI velocity model developed to accurately locate the microseismic events, we theoretically calculated a continuous profile of the magnitude of the least principal stress with depth. This stress profile explains the apparent vertical hydraulic fracture growth as inferred from the well-constrained depths of associated microseismic events. Finally, we demonstrate that because of the upward propagation of hydraulic fractures from the Niobrara C to the Niobrara A, the latter formation experienced considerably more shear stimulation, which may contribute to the greater production of oil and gas from that formation.

scholarly journals A multi-perforation staged fracturing experimental study on hydraulic fracture initiation and propagation

2020 ◽  
Vol 38 (6) ◽  
pp. 2466-2484
Author(s):  
Jianguang Wei ◽  
Saipeng Huang ◽  
Guangwei Hao ◽  
Jiangtao Li ◽  
Xiaofeng Zhou ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Initiation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Tight Sandstone ◽  
Heterogeneous Samples ◽  
Initiation And Propagation

Hydraulic fracture initiation and propagation are extremely important on deciding the production capacity and are crucial for oil and gas exploration and development. Based on a self-designed system, multi-perforation cluster-staged fracturing in thick tight sandstone reservoir was simulated in the laboratory. Moreover, the technology of staged fracturing during casing completion was achieved by using a preformed perforated wellbore. Three hydraulic fracturing methods, including single-perforation cluster fracturing, multi-perforation cluster conventional fracturing and multi-perforation cluster staged fracturing, were applied and studied, respectively. The results clearly indicate that the hydraulic fractures resulting from single-perforation cluster fracturing are relatively simple, which is difficult to form fracture network. In contrast, multi-perforation cluster-staged fracturing has more probability to produce complex fractures including major fracture and its branched fractures, especially in heterogeneous samples. Furthermore, the propagation direction of hydraulic fractures tends to change in heterogeneous samples, which is more likely to form a multi-directional hydraulic fracture network. The fracture area is greatly increased when the perforation cluster density increases in multi-perforation cluster conventional fracturing and multi-perforation cluster-staged fracturing. Moreover, higher perforation cluster densities and larger stage numbers are beneficial to hydraulic fracture initiation. The breakdown pressure in homogeneous samples is much higher than that in heterogeneous samples during hydraulic fracturing. In addition, the time of first fracture initiation has the trend that the shorter the initiation time is, the higher the breakdown pressure is. The results of this study provide meaningful suggestions for enhancing the production mechanism of multi-perforation cluster staged fracturing.

Intelligent Fracture Diagnostic Procedure Using Smart Microchip Proppants Data

2021 ◽  
Author(s):  
Vuong Van Pham ◽  
Amirmasoud Kalantari Dahaghi ◽  
Shahin Negahban ◽  
William Fincham ◽  
Aydin Babakhani
Keyword(s):  
Affine Transformation ◽  
Oil And Gas ◽  
Fracture Network ◽  
Unsupervised Clustering ◽  
Sensor Data ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Novel Approach ◽  
House Design ◽  
Fracture Mapping

Abstract Unconventional oil and gas reservoir development requires an understanding of the geometry and complexity of hydraulic fractures. The current categories of fracture diagnostic approaches include methods for near-wellbore (production and temperature logs, tracers, borehole imaging) and far-field techniques (micro-seismic fracture mapping). These techniques provide an indirect and/or interpreted fracture geometry. Therefore, none of these methods consistently provides a fully detailed and accurate description of the character of created hydraulic fractures. This study proposes a novel approach that uses direct data from the injected fine size and battery-less Smart MicroChip Proppants (SMPs) to map the fracture geometry. This novel approach enables direct, fast, and smart of the received high-resolution geo-sensor data from the SMPs collected in high pressure and high-temperature environment and maps the fracture network using the proposed Intelligent and Integrated Fracture Diagnostic Platform (IFDP), which is a closed-loop architecture and is based on multi-dimensional projection, unsupervised clustering, and surface reconstruction. Affine transformation and a shallow ANN are integrated to control the stochasticity of clustering. IFDP proves its efficacy in fracture diagnostics for 3 in-house design synthetic fracture networks, with 100% consistency, rated "fairly satisfied" to "highly satisfied" in prediction capability, and between 85-100% in execution robustness. The integration of the couple affine transformation-ANN increases the performance of unsupervised clustering in IFDP.

scholarly journals Review of pseudo-three-dimensional modeling approaches in hydraulic fracturing

2021 ◽  
Author(s):  
Hai T. Nguyen ◽  
Jang Hyun Lee ◽  
Khaled A. Elraies
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Three Dimensional ◽  
Network Models ◽  
Fracture Network ◽  
Injection Rate ◽  
Height Growth ◽  
Early Developmental Stage ◽  
Hydraulic Fractures ◽  
Equilibrium Height

AbstractIn the field of hydraulic fracture modeling, the pseudo-three-dimensional (P3D) approach is an efficient and practical computational tool serving as a compromise between two-dimensional and planar three-dimensional models. This review discusses the P3D modeling approach from its early developmental stage in the 1980s to the present. The evolution of P3D modeling is drawn over time based on the major differences in the governing formulation and assumptions considered by each model. The problems of equilibrium height growth and vertical viscous fluid resistance (i.e., non-equilibrium height growth) emphasize the primary differences among these models. Besides, the P3D-based complex fracture network models for shale oil and gas reservoirs accounting for the interaction between preexisting natural fractures and induced hydraulic fractures are discussed. Finally, in the application section, several simulations are reported to demonstrate the validation of the P3D numerical algorithm by comparing it with the Perkins–Kern–Nordgren (PKN) large and small asymptotic solutions, as well as the effect of time-dependent variable injection rates on the hydraulic fracture propagation. The results showed a good matching between P3D and PKN solutions and a significant effect of the wellbore variable injection rate on the evolution of the fracture length.

Containment of Massive Hydraulic Fractures

1978 ◽  
Vol 18 (01) ◽  
pp. 27-32 ◽  
Author(s):  
E.R. Simonson ◽  
A.S. Abou-Sayed ◽  
R.J. Clifton
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Propagation ◽  
Rocky Mountain ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Pressure Gradients ◽  
In Situ Stresses ◽  
Gas Bearing

Abstract Hydraulic fracture containment is discussed in relationship to linear elastic fracture mechanics. Three cases are analyzed,the effect of different material properties for the pay zone and the barrier formation,the characteristics of fracture propagation into regions of varying in-situ stress, propagation into regions of varying in-situ stress, andthe effect of hydrostatic pressure gradients on fracture propagation into overlying or underlying barrier formations. Analysis shows the importance of the elastic properties, the in-situ stresses, and the pressure gradients on fracture containment. Introduction Application of massive hydraulic fracture (MHF) techniques to the Rocky Mountain gas fields has been uneven, with some successes and some failures. The primary thrust of rock mechanics research in this area is to understand those factors that contribute to the success of MHF techniques and those conditions that lead to failures. There are many possible reasons why MHF techniques fail, including migration of the fracture into overlying or underlying barrier formations, degradation of permeability caused by application of hydraulic permeability caused by application of hydraulic fracturing fluid, loss of fracturing fluid into preexisting cracks or fissures, or extreme errors in preexisting cracks or fissures, or extreme errors in estimating the quantity of in-place gas. Also, a poor estimate of the in-situ permeability can result in failures that may "appear" to be caused by the hydraulic fracture process. Previous research showed that in-situ permeabilities can be one order of magnitude or more lower than permeabilities measured at near atmospheric conditions. Moreover, studies have investigated the degradation in both fracture permeability and formation permeability caused by the application of hydraulic fracture fluids. Further discussion of this subject is beyond the scope of this paper. This study will deal mainly with the containment of hydraulic fractures to the pay zone. In general, the lithology of the Rocky Mountain region is composed of oil- and gas-bearing sandstone layers interspaced with shales (Fig. 1). However, some sandstone layers may be water aquifers and penetration of the hydraulic fracture into these penetration of the hydraulic fracture into these aquifer layers is undesirable. Also, the shale layers can separate producible oil- and gas-bearing zones from nonproducible ones. Shale layers between the pay zone and other zones can be vital in increasing successful stimulation. If the shale layers act as barrier layers, the hydraulic fracture can be contained within the pay zone. The in-situ stresses and the stiffness, as characterized by the shear modulus of the zones, play significant roles in the containment of a play significant roles in the containment of a hydraulic fracture. The in-situ stresses result from forces in the earth's crust and constitute the compressive far-field stresses that act to close the hydraulic fracture. Fig. 2 shows a schematic representation of in-situ stresses acting on a vertical hydraulic fracture. Horizontal components of in-situ stresses may vary from layer to layer (Fig. 2). For example, direct measurements of in-situ stresses in shales has shown the minimum horizontal principal stress is nearly equal to the overburden principal stress is nearly equal to the overburden stress. SPEJ P. 27

I-GeoSensing Fracture Diagnostic I-GSFD for Fast Processing of the Smart Microchip Proppants Data

2021 ◽  
Author(s):  
Vuong Pham ◽  
Amirmasoud Dahaghi ◽  
Shahin Negahban ◽  
William Fincham ◽  
Aydin Babakhani
Keyword(s):  
Oil And Gas ◽  
Mesh Size ◽  
Fracture Network ◽  
Sensor Data ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Real Time Processing ◽  
Novel Approach ◽  
Fast Processing ◽  
Fracture Mapping

Abstract Unconventional oil and gas reservoir development requires an understanding of the geometry and complexity of the hydraulic fractures. The current categories of fracture diagnostic approaches include methods for near-wellbore (production & temperature logs, tracers, and borehole imaging) and far-field techniques (micro-seismic fracture mapping). These techniques provide an indirect and interpreted fracture geometry. Therefore, none of these methods consistently provides a fully detailed and accurate description of the characteristic of the subsurface hydraulic fractures. This study proposes a novel approach that uses direct data from the injected fine size (proppant Mesh size equivalence) and battery-less, Smart MicroChip Proppants (SMPs), to map the fracture geometry. This novel approach enables direct, fast, smart, and real-time processing of the received high-resolution geo-sensor data from the SMPs collected in high pressure and high-temperature environment and maps the fracture network using the proposed i-Geosensing Fracture Diagnostic (i-GSFD), which is a closed-loop architecture. i-GSFD is based on multi-dimensional projection unsupervised clustering, and integrated Bayesian optimizer to control the stochastic nature of any components in the loop.

Hydraulic fractures productivity performance in tight gas sands—a numerical simulation approach

2011 ◽  
Vol 51 (1) ◽  
pp. 519
Author(s):  
Jakov Ostojic ◽  
Reza Rezaee ◽  
Hassan Bahrami
Keyword(s):  
Hydraulic Fracture ◽  
Effective Field ◽  
Gas Production ◽  
Simulation Software ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Gas Recovery ◽  
Single Well ◽  
The Impact

The increasing global demand for energy along with the reduction in conventional gas reserves has lead to the increasing demand and exploration of unconventional gas sources. Hydraulically-fractured tight gas reservoirs are one of the most common unconventional sources being produced today and look to be a regular source of gas in the future. Hydraulic fracture orientation and spacing are important factors in effective field drainage and gas recovery. This paper presents a 3D single well hydraulically fractured tight gas model created using commercial simulation software, which will be used to simulate gas production and synthetically generate welltest data. The hydraulic fractures will be simulated with varying sizes and different numbers of fractures intersecting the wellbore. The focus of the simulation runs will be on the effect of hydraulic fracture size and spacing on well productivity performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fracturing scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity performance.

Effect of Fluid Compressibility on Toughness-Dominated Hydraulic Fractures With Leakoff

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2118-2132 ◽  
Author(s):  
Di Wang ◽  
Mian Chen ◽  
Yan Jin ◽  
Andrew. P. Bunger
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Fracturing Fluids ◽  
Fracture Shape ◽  
Carbon Dioxide Co2 ◽  
Fracture Growth ◽  
Fluid Compressibility

Summary Hydraulic fracturing using supercritical carbon dioxide (CO2) has a recognized potential to grow in importance for unconventional oil and gas reservoirs. It is characterized by higher compressibility than traditional liquid-phase hydraulic-fracturing fluids. Motivated by the larger compressibility of supercritical CO2, this paper considers the problem of a hydraulic fracture in which a compressible fluid is injected at a constant rate to drive a hydraulic fracture in a permeable and brittle rock. The two cases of a plane-strain fracture and a penny-shaped fracture are considered. It is shown that for many practical cases, the formation has a large enough fracture toughness that the propagation is in a regime for which the pressure inside the hydraulic fracture can be treated as spatially uniform (“toughness dominated”). Both numerical simulations and analytical solutions for the relevant limiting regimes show that fluid compressibility affects fracture shape only at the very beginning period, which corresponds to the storage regime, and has little effect on fracture growth in the leakoff regime. Overall, because the transition from the storage regime to the leakoff regime is expected to often take place in a short time after the fracture starts propagating, the influence of compressibility in the storage regime is very brief and can be quickly ignored. Therefore, even relatively sizable fluid compressibility has almost no effect on fracture growth in the toughness-dominated regime when leakoff is taken into account.

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