Experimental Study on Injection Pressure Response and Fracture Geometry during Temporary Plugging and Diverting Fracturing

SPE Journal ◽  
2020 ◽  
Vol 25 (02) ◽  
pp. 573-586 ◽  
Author(s):  
Bo Wang ◽  
Fujian Zhou ◽  
Chen Yang ◽  
Daobing Wang ◽  
Kai Yang ◽  
...  
Keyword(s):  
Injection Pressure ◽  
Fracture Network ◽  
Pressure Response ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Breakdown Pressure ◽  
Multiple Fractures ◽  
Differential Stress ◽  
Fracture Geometry ◽  
Stimulated Reservoir Volume

Summary Temporary plugging and diverting fracturing (TPDF) has become one of the fastest-growing techniques to maximize the stimulated reservoir volume (SRV). During the field operation of TPDF, diverters are injected to redirect the hydraulic fractures into the under-stimulated region of the reservoir, and, thus, to obtain better coverage of the created fracture network. In this study, the commonly used true tri-axial hydraulic fracturing system is modified to investigate the influences of various factors on the injection pressure response and resultant fracture geometry during diversion treatments. The experimental results show the feasibility of creating multiple fractures through TPDF, and more importantly give the following findings: (1) a complex diverted fracture network tends to be created at a small differential stress (2.5 MPa in this case), while diverted fractures tend to grow parallel to the initial fractures at a high differential stress (7.5 MPa in this case); (2) with the same concentration in the fracturing fluid, 40-mesh powder-shaped diverters can plug the created fractures and increase the net pressure more rapidly than 6-mm fiber-shaped diverters; (3) an excess of diverters can lead to a strong injection pressure response, and, thus, enhance the difficulty of creating multiple fractures; (4) when diverters are injected with the fracturing fluid, no obvious breakdown pressure or propagation pressure is shown during the fracture propagation.

scholarly journals Pressure Response of a Horizontal Well in Tight Oil Reservoirs with Stimulated Reservoir Volume

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Peng Chen ◽  
Changpeng Hu ◽  
Pingguo Zou ◽  
Lili Lin ◽  
Song Lu ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Fracture Network ◽  
Stress Sensitivity ◽  
Pressure Response ◽  
Hydraulic Fractures ◽  
Tight Oil ◽  
Stimulated Reservoir Volume ◽  
Pressure Behavior ◽  
Reservoir Volume ◽  
Interpretation Model

Abstract Stimulated reservoir volume is an effective stimulation measure and creates a complex fracture network, but the description and characterization of fracture network are very difficult. Well test analysis is a common method to describe the fracture network, and it is the key to build a proper interpretation model. However, most published works only consider the shape of the fractured area or the stress sensitivity effect, and few works take both factors into account. In this paper, based on reservoir properties and flow law after a stimulated reservoir volume, an interpretation model is established with an arbitrary shape of the fractured area and stress sensitivity effect of different flow areas. The model is solved to conduct the pressure response using Laplace transform, point source function, and boundary element theory. The influence of fractures’ parameters and stress sensitivity effect is analyzed on the pressure behavior. Results from this study show that the special flow regimes for a horizontal well with a stimulated reservoir volume are (1) bilinear flow dominated by hydraulic fractures, (2) linear flow dominated by formation around the hydraulic fractures, (3) crossflow from a matrix system to the fractured area, and (4) radial flow control by properties of the fractured area. Parameters of hydraulic fractures mainly affect the early stage of pressure behavior. On the contrary, the stress-sensitive effect mainly affects the middle and late stages; the stronger the stress sensitivity effect is, the more obvious the effect is. The findings of this study can help for better understanding of the fracture network in a tight oil reservoir with a stimulated reservoir volume.

Can We Engineer Better Multistage Horizontal Completions? Evidence of the Importance of Near-wellbore Fracture Geometry from Theory, Lab and Field Experiments

2015 ◽  
Author(s):  
B.. Lecampion ◽  
J.. Desroches ◽  
X.. Weng ◽  
J.. Burghardt ◽  
J.E.. E. Brown
Keyword(s):  
Pressure Drop ◽  
Field Experiments ◽  
Horizontal Wells ◽  
Fracture Plane ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Fracture Geometry ◽  
Complex Fracture ◽  
Limited Entry ◽  
The Impact

Abstract There is accepted evidence that multistage fracturing of horizontal wells in shale reservoirs results in significant production variation from perforation cluster to perforation cluster. Typically, between 30 and 40% of the clusters do not significantly contribute to production while the majority of the production comes from only 20 to 30% of the clusters. Based on numerical modeling, laboratory and field experiments, we investigate the process of simultaneously initiating and propagating several hydraulic fractures. In particular, we clarify the interplay between the impact of perforation friction and stress shadow on the stability of the propagation of multiple fractures. We show that a sufficiently large perforation pressure drop (limited entry) can counteract the stress interference between different growing fractures. We also discuss the robustness of the current design practices (cluster location, limited entry) in the presence of characterized stress heterogeneities. Laboratory experiments highlight the complexity of the fracture geometry in the near-wellbore region. Such complex fracture path results from local stress perturbations around the well and the perforations, as well as the rock fabric. The fracture complexity (i.e., the merging of multiple fractures and the reorientation towards the preferred far-field fracture plane) induces a strong nonlinear pressure drop on a scale of a few meters. Single entry field experiments in horizontal wells show that this near-wellbore effect is larger in magnitude than perforation friction and is highly variable between clusters, without being predictable. Through a combination of field measurements and modeling, we show that such variability results in a very heterogeneous slurry rate distribution; and therefore, proppant intake between clusters during a stage, even in the presence of limited entry techniques. We also note that the estimated distribution of proppant intake between clusters appears similar to published production log data. We conclude that understanding and accounting for the complex fracture geometry in the near-wellbore is an important missing link to better engineer horizontal well multistage completions.

Numerical Investigation of Complex Hydraulic Fracture Development in Naturally Fractured Reservoirs

2015 ◽  
Author(s):  
Wu Kan ◽  
Jon E. Olson
Keyword(s):  
Fracture Propagation ◽  
Injection Pressure ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Differential Stress ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Development ◽  
Fracture Complexity ◽  
Shale Reservoirs

Abstract Complex fracture networks have become more evident in shale reservoirs due to the interaction between pre-existing natural and hydraulic fractures. Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density natural fractures. In this study, we simulated simultaneous multiple fracture propagation within a single fracturing stage using a complex hydraulic fracture development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified three-dimensional displacement discontinuity method was implemented to more accurately calculate fracture displacements and fracture-induced dynamic stress changes than our previously developed pseudo-3d model. The effects of perforation cluster spacing, differential stress (SHmax - Shmin) and various geometry natural fracture patterns on injection pressure and fracture complexity were investigated. The single stage simulation results shown that (1) higher differential stress suppresses fracture length and increases injection pressure; (2) there is an optimal choice for the number of fractures per stage to maximize effective fracture surface area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of natural fracture patterns (various regular pattern geometries were investigated). Natural fractures with small relative angle to hydraulic fractures are more likely to control fracture propagation path. Also, natural fracture patterns with more long fractures tend to increase the likelihood to dominate the preferential fracture trend of fracture trajectory. Our numerical model can provide a physics-based complex fracture network that can be imported into reservoir simulation models for production analysis. The overall sensitivity results presented should serve as guidelines for fracture complexity analysis.

scholarly journals Effect of Joint Geometrical Parameters on Hydraulic Fracture Network Propagation in Naturally Jointed Shale Reservoirs

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-23 ◽  
Author(s):  
Zhaohui Chong ◽  
Qiangling Yao ◽  
Xuehua Li
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Geometrical Parameters ◽  
Breakdown Pressure ◽  
Opening Mode ◽  
Hydraulic Fracture Network ◽  
Shale Reservoirs ◽  
Network Pattern

The presence of a significant amount of discontinuous joints results in the inhomogeneous nature of the shale reservoirs. The geometrical parameters of these joints exert effects on the propagation of a hydraulic fracture network in the hydraulic fracturing process. Therefore, mechanisms of fluid injection-induced fracture initiation and propagation in jointed reservoirs should be well understood to unleash the full potential of hydraulic fracturing. In this paper, a coupled hydromechanical model based on the discrete element method is developed to explore the effect of the geometrical parameters of the joints on the breakdown pressure, the number and proportion of hydraulic fractures, and the hydraulic fracture network pattern generated in shale reservoirs. The microparameters of the matrix and joint used in the shale reservoir model are calibrated through the physical experiment. The hydraulic parameters used in the model are validated through comparing the breakdown pressure derived from numerical modeling against that calculated from the theoretical equation. Sensitivity analysis is performed on the geometrical parameters of the joints. Results demonstrate that the HFN pattern resulting from hydraulic fracturing can be roughly divided into four types, i.e., crossing mode, tip-to-tip mode, step path mode, and opening mode. As β (joint orientation with respect to horizontal principal stress in plane) increases from 0° to 15° or 30°, the hydraulic fracture network pattern changes from tip-to-tip mode to crossing mode, followed by a gradual decrease in the breakdown pressure and the number of cracks. In this case, the hydraulic fracture network pattern is controlled by both γ (joint step angle) and β. When β is 45° or 60°, the crossing mode gains dominance, and the breakdown pressure and the number of cracks reach the lowest level. In this case, the HFN pattern is essentially dependent on β and d (joint spacing). As β reaches 75° or 90°, the step path mode is ubiquitous in all shale reservoirs, and the breakdown pressure and the number of the cracks both increase. In this case, β has a direct effect on the HFN pattern. In shale reservoirs with the same β, either decrease in k (joint persistency) and e (joint aperture) or increase in d leads to the increase in the breakdown pressure and the number of cracks. It is also found that changes in d and e result in the variation in the proportion of different types of hydraulic fractures. The opening mode of the hydraulic fracture network pattern is observed when e increases to 1.2 × 10−2 m.

scholarly journals Modeling Simultaneous Multiple Fracturing Using the Combined Finite-Discrete Element Method

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-20 ◽  
Author(s):  
Quansheng Liu ◽  
Lei Sun ◽  
Pingli Liu ◽  
Lei Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Solid Phase ◽  
Horizontal Wells ◽  
In Situ Stress ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Fracture Geometry ◽  
Stress Shadow ◽  
Oil Gas

Simultaneous multiple fracturing is a key technology to facilitate the production of shale oil/gas. When multiple hydraulic fractures propagate simultaneously, there is an interaction effect among these propagating hydraulic fractures, known as the stress-shadow effect, which has a significant impact on the fracture geometry. Understanding and controlling the propagation of simultaneous multiple hydraulic fractures and the interaction effects between multiple fractures are critical to optimizing oil/gas production. In this paper, the FDEM simulator and a fluid simulator are linked, named FDEM-Fluid, to handle hydromechanical-fracture coupling problems and investigate the simultaneous multiple hydraulic fracturing mechanism. The fractures propagation and the deformation of solid phase are solved by FDEM; meanwhile the fluid flow in the fractures is modeled using the principle of parallel-plate flow model. Several tests are carried out to validate the application of FDEM-Fluid in hydraulic fracturing simulation. Then, this FDEM-Fluid is used to investigate simultaneous multiple fractures treatment. Fractures repel each other when multiple fractures propagate from a single horizontal well, while the nearby fractures in different horizontal wells attract each other when multiple fractures propagate from multiple parallel horizontal wells. The in situ stress also has a significant impact on the fracture geometry.

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.

scholarly journals Characteristics of the fracture geometry and the injection pressure response during near-wellbore diverting fracturing

2021 ◽  
Vol 7 ◽  
pp. 491-501
Author(s):  
Bo Wang ◽  
Fujian Zhou ◽  
Hang Zhou ◽  
Hui Ge ◽  
Lizhe Li
Keyword(s):  
Injection Pressure ◽  
Pressure Response ◽  
Fracture Geometry

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.

Characterizing the Stimulated Reservoir Volume During Hydraulic Fracturing-Connecting the Pressure Fall-Off Phase to the Geomechanics of Fracturing

2018 ◽  
Vol 85 (10) ◽  
Author(s):  
Erfan Sarvaramini ◽  
Maurice B. Dusseault ◽  
Robert Gracie
Keyword(s):  
Hydraulic Fracturing ◽  
Fracture Network ◽  
Natural Fracture ◽  
Breakdown Pressure ◽  
Pressure Derivative ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Flow Capacity ◽  
Pressure Fall

Microseismic imaging of the hydraulic fracturing operation in the naturally fractured rocks confirms the existence of a stimulated volume (SV) of enhanced permeability. The simulation and characterization of the SV evolution is uniquely challenging given the uncertainty in the nature of the rock mass fabrics as well as the complex fracturing behavior of shear and tensile nature, irreversible plastic deformation and damage. In this paper, the simulation of the SV evolution is achieved using a nonlocal poromechanical plasticity model. Effects of the natural fracture network are incorporated via a nonlocal plasticity characteristic length, ℓ. A nonlocal Drucker–Prager failure model is implemented in the framework of Biot's theory using a new implicit C0 finite element method. First, the behavior of the SV for a two-dimensional (2D) geomechanical injection problem is simulated and the resulting SV is assessed. It is shown that breakdown pressure and stable fracturing pressure are the natural outcomes of the model and both depend upon ℓ. Next, the post-shut-in behavior of the SV is analyzed using the pressure and pressure derivative plots. A bilinear flow regime is observed and it is used to estimate the flow capacity of the SV. The results show that the flow capacity of the SV increases as ℓ decreases (i.e., as the SV behaves more like a single hydraulic fracture); however, for 0.1m≤ℓ≤1m, the calculated flow capacity indicates that the conductivity of the SV is finite. Finally, it is observed that as ℓ tends to zero, the flow capacity of the SV tends to infinity and the SV behaves like a single infinitely conducting fracture.

Numerical Modeling of Fracture Propagation During Temporary-Plugging Fracturing

SPE Journal ◽  
2019 ◽  
Vol 25 (03) ◽  
pp. 1503-1522 ◽  
Author(s):  
Yushi Zou ◽  
Xinfang Ma ◽  
Shicheng Zhang
Keyword(s):  
Influence Factors ◽  
Injection Pressure ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Pumping Rate ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Interaction Behavior ◽  
Before And After ◽  
Horizontal Differential Stress

Summary Temporary-plugging fracturing (TPF) is becoming a promising technique for maximizing the stimulated-reservoir volume in tight reservoirs by injecting diverting agents to plug the preferred perforations and/or hydraulic fractures (HFs). Previous work has developed diverting agents and evaluated their blocking efficiency. However, the mechanism and dominant influence factors of HF growth during TPF remain poorly understood to date, which restricts the application of this technique. To understand the problem and help improve the TPF design, this study simulated the HF-propagation process during TPF in a naturally fractured formation using a previously developed 3D discrete-element-method (DEM) -based complex fracture model. Plugged fracture elements with negligible permeability were incorporated into the model to characterize the blocking intervals of diverting agents within HFs. Parameters, including horizontal differential stress (Δσh), natural-fracture (NF) properties, the number of pluggings, plugging positions, and pumping rate, were investigated to determine their effects on the HF/NF-interaction behavior and the resulting HF geometry. The change in injection pressure before and after plugging under different conditions was also recorded in detail. Modeling results show that the HF/NF-interaction behavior might surprisingly change before and after plugging the preferred HF, ranging from HF crossing of NFs to HF opening of NFs. Notably, Δσh is still the most influential geological parameter that governs the HF-growth behavior during TPF. For a moderate Δσh (=8 MPa), the growth of a single planar HF before plugging can be changed easily into a complex HF network (HFN) through opening of NFs after plugging in the target stimulated region (TSR). In this case, the complexity and covering area of the resulting HFN is closely related to the NF density (positive correlation) and plugging positions. However, for a high Δσh (=12 MPa), opening (usually partially) the NFs after plugging is difficult even in formations with a high density of NFs. In such a case, a large volume of fluid, a high pumping rate, and several repeat pluggings during TPF are necessary. The results of this study help to understand the HF-growth mechanism during TPF and help to optimize the treatment design of TPF and to adjust it in a timely manner.

Sign in / Sign up

Export Citation Format

Share Document