Integration of Borehole Acoustic Reflectivity Survey and Fracture Pressure Analysis to Determine Properties of Far-Field Heterogeneities During Stimulation in Tight Reservoirs

2021 ◽  
Author(s):  
Dmitriy Abdrazakov ◽  
Evgeniy Karpekin ◽  
Anton Filimonov ◽  
Ivan Pertsev ◽  
Askhat Burlibayev ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Rock Properties ◽  
Production Data ◽  
Far Field ◽  
Suggested Approach ◽  
Fracture Properties ◽  
Fracture Pressure ◽  
Heterogeneous Features ◽  
Pressure Analysis

Abstract The presence of conductive and extended heterogeneous features not connected to the wellbore and located beyond the investigation depths of standard characterization tools can be the reason for unexpected loss of net pressure during stimulation treatments due to the hydraulic fracture breakthrough into these heterogeneous areas. In current field practice, if such breakthrough occurs, it is considered as bad luck without the possibility of the quantitative analysis. This mindset can be changed in favor of the stimulation and reservoir management success using an approach that ties the thorough fracture pressure analysis with the output of the specific acoustic reflectivity survey capable of identifying position, shape, and orientation of far-field heterogeneous features. The approach consists of four steps and is applicable to cases when the hydraulic fracture experiences breakthrough into the heterogeneity. First, before the stimulation treatments, at the reservoir characterization stage, a borehole acoustic reflectivity survey is run. Gathered data are interpreted and visualized according to a specific workflow that yields the image of the heterogeneous areas located around the wellbore in the radius of several tens of meters. Second, the hydraulic fracturing treatment is performed, and fracture pressure analysis is performed, which identifies the pressure drops typical for the breakthrough. Third, after the breakthrough into the heterogeneity is confirmed, the distance to this heterogeneity is used as a marker for calibration of the fracture properties and geometry. Finally, the post-stimulation pressure and production data are used to define the properties of the heterogeneous features, such as conductivity and approximate dimensions. The comprehensive field application example of the suggested approach confirmed its effectiveness. For the tight carbonate formations, the heterogeneity in a form of fracture corridor was revealed by the acoustic reflectivity survey at least 20 m away from the wellbore. The breakthrough into this heterogeneity was observed during the acid fracturing treatment. The distance to the heterogeneity and observed pumping time to breakthrough were used as markers characterizing fracture propagation; reservoir and rock properties were adjusted using a fracturing simulator to obtain this fracture propagation. Finally, the post-stimulation production data were analyzed to determine infinite conductivity of the fracture corridor and quantify its extent downward. Data gathered during reservoir and hydraulic fracture properties calibration allowed for optimization of stimulation strategy of the target layer throughout the field; the information about the heterogeneity’s properties allowed for optimization of the completion and reservoir development strategy.

Hydraulic Fracturing Diagnostics Utilizing Near and Far-Field Distributed Acoustic Sensing DAS Data Correspondences

2021 ◽  
Author(s):  
Yinghui Wu ◽  
Robert Hull ◽  
Andrew Tucker ◽  
Craig Rice ◽  
Peter Richter ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Near Field ◽  
Fracture Propagation ◽  
Cost Effective ◽  
Hydraulic Fractures ◽  
Far Field ◽  
Distributed Temperature Sensing ◽  
Acoustic Sensing ◽  
Distributed Acoustic Sensing ◽  
Multiple Fibers

Abstract Distributed fiber-optic sensing (DFOS) has been utilized in unconventional reservoirs for hydraulic fracture efficiency diagnostics for many years. Downhole fiber cables can be permanently installed external to the casing to monitor and measure the uniformity and efficiency of individual clusters and stages during the completion in the near-field wellbore environment. Ideally, a second fiber or multiple fibers can be deployed in offset well(s) to monitor and characterize fracture geometries recorded by fracture-driven interactions or frac-hits in the far-field. Fracture opening and closing, stress shadow creation and relaxation, along with stage isolation can be clearly identified. Most importantly, fracture propagation from the near to far-field can be better understood and correlated. With our current technology, we can deploy cost effective retrievable fibers to record these far-field data. Our objective here is to highlight key data that can be gathered with multiple fibers in a carefully planned well-spacing study and to evaluate and understand the correspondence between far-field and near-field Distributed Acoustic Sensing (DAS) data. In this paper, we present a case study of three adjacent horizontal wells equipped with fiber in the Permian basin. We can correlate the near-field fluid allocation across a stage down to the cluster level to far-field fracture driven interactions (FDIs) with their frac-hit strain intensity. With multiple fibers we can evaluate fracture geometry, the propagation of the hydraulic fractures, changes in the deformation related to completion designs, fracture complexity characterization and then integrate the results with other data to better understand the geomechanical processes between wells. Novel frac-hit corridor (FHC) is introduced to evaluate stage isolation, azimuth, and frac-hit intensity (FHI), which is measured in far-field. Frac design can be evaluated with the correlation from near-field allocation to far-field FHC and FHI. By analyzing multiple treatment and monitor wells, the correspondence can be further calibrated and examined. We observe the far-field FHC and FHI are directly related to the activities of near-field clusters and stages. A leaking plug may directly result in FHC overlapping, gaps and variations in FHI, which also can be correlated to cluster uniformity. A near-far field correspondence can be established to evaluate FHC and FHI behaviors. By utilizing various completion designs and related measurements (e.g. Distributed Temperature Sensing (DTS), gauges, microseismic etc.), optimization can be performed to change the frac design based on far-field and near-field DFOS data based on the Decision Tree Method (DTM). In summary, hydraulic fracture propagation can be better characterized, measured, and understood by deploying multiple fibers across a lease. The correspondence between the far-field measured FHC and FHI can be utilized for completion evaluation and diagnostics. As the observed strain is directly measured, completion engineering and geoscience teams can confidently optimize their understanding of the fracture designs in real-time.

scholarly journals An Investigation into the Effects of Weak Interfaces on Fracture Height Containment in Hydraulic Fracturing

Energies ◽  
2019 ◽  
Vol 12 (17) ◽  
pp. 3245 ◽  
Author(s):  
Zheng ◽  
Liu ◽  
Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Control Method ◽  
Fracture Propagation ◽  
Rock Properties ◽  
Interface Fracture ◽  
Weak Interface ◽  
Height Control ◽  
Fracture Height ◽  
Fracture Height Containment

Hydraulic fracturing is an effective method for developing unconventional reservoirs. The fracture height is a critical geometric parameter for fracturing design but will be limited by a weak interface. Fracture containment occurs when fracture propagation terminates at layer interfaces that are weaker than the surrounding rock. It always occurs in multilayer formation. Therefore, the mechanism of fracture height containment guides fracture height control in hydraulic fracturing. In order to study the fracture containment mechanism, this paper first calculates the propagation behaviour of the fracture in 3D under the influence of a weak interface through a block discrete element method and analyzes the geometric characteristics of the fracture after it meets the weak interface. Then, the induced stress of the hydraulic fracture on the weak interface is calculated by fracture mechanics theory, and the mechanism of blunting at the fracture tip is explained. Then, two kinds of interface slippage that can lead to blunting of the fracture tip are discussed. Based on the behavior of shear slippage at the interface, a control method for multilayer fracturing in thin sand-mud interbed and pay zone fracturing in shale is proposed. The results show that the fracture height is still limited by the weak interface in the formation without the difference of in-situ stress and rock properties. Interface slippage is the main factor impeding fracture propagation. Fracture height containment can be adjusted and controlled by changing the angle between the hydraulic fracture, the interface, and the stress state to strengthen and stiffen the interface. This study has a certain guiding significance for fracture height control in the design of hydraulic fracturing of shale or thin sand-mud interbed reservoirs.

Three-Dimensional Hydraulic Fracture Propagation in the Presence of Stress Variations

1983 ◽  
Vol 23 (06) ◽  
pp. 870-878 ◽  
Author(s):  
Ian D. Palmer ◽  
H.B. Carroll
Keyword(s):  
Boundary Condition ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Fracture Propagation ◽  
Rock Properties ◽  
Vertical Fracture ◽  
Hydraulic Fracture Propagation ◽  
Net Pressure ◽  
Fracture Height ◽  
Stress Contrast

Abstract Models of three-dimensional (3D) fracture propagation are being developed to study the effect of variations of stress and rock properties on fracture height and bottomhole pressure (BHP). Initially a blanket sand bounded by zones of higher minimum in-situ stress is considered, with stresses symmetrical about both the pay-zone axis and the wellbore. An elliptical fracture perimeter is assumed. Fluid flows are one-dimensional (1D) Newtonian in the direction of the pay zone. Two models, FL1 and FL2, are developed. In FL1, a discontinuous stress variation is approximated by a y2 variation in the vertical coordinate, and the fracture criterion, Ki = Kc, is satisfied at both major and minor axes. The net pressure at the tip, Lf, of the long axis required by the boundary condition Ki = Kc does not seem crucial in determining fracture height or BHP (compare with one group of published models that assumes p = 0 at Lf). Model FL2 properly represents the discontinuous stresses, and satisfies Ki = Kc at the wellbore but not at the tip of the long axis. A parametric study is made, with both models, of the comparative effects of stress contrast, Kc, pay-zone height, h, and Young's modulus, E, on fracture height and BHP. Results indicate that Kc does not have as much effect as either E or, at least for large stress contrasts. Model FL2 suggests the possibility of a rapid growth in fracture height as is reduced. Such modeling may be able to give an upper or "safe" limit on the pumping parameters ( and ) to ensure good containment. When the stress contrast is high, 700 psi [4826 kPa], an analytic derivation of BHP appears to be a good approximation for the parameters we use, if everywhere the fracture height is assumed equal to the pay zone height. Although leakoff is neglected here, subsequent modeling results show that, for leak off coefficients 0.001 ft- min [3.9 × 10 -5 m.s ], the results herein are a good approximation to the case when leak off is included. Introduction In their essence, models of hydraulic fracture propagation involve elasticity theory and fluid mechanics. The first is concerned with the fracture opening or width, w(p), as a function of net pressure on the fracture faces, while the second is concerned with the pressure drop, p(w), caused by the flow of viscous fluids in the fracture. Simultaneous solution of these equations includes a boundary condition that often takes the form Ki = Kc, where Ki is the stress-intensity factor at a point on the fracture tip, and Kc is the fracture toughness. The final solution is very complex in 3D, when a vertical fracture can expand vertically as well as horizontally along the pay zone. Thus, the first solutions were essentially two-dimensional (2D), and they assumed that the fracture height, hf, was fixed at the pay zone height, h. The 2D solutions were clustered in two groups as summarized by Nordgren, Perkins, and Geertsma and Haafkens. The first grouping, based on a model by Christianovich and Zheltov, assumed that the sides of an elongated, vertical fracture were parallel (i.e., free slippage between the pay and bounding zones, or no vertical stiffness). Other papers in this grouping included Geertsma and de Klerk, Daneshy and Settari. SPEJ P. 870^

An Efficient Hydraulic Fracture Geometry Calibration Workflow Using Microseismic Data, Geomechanics, DFN Models, and History Matching

2021 ◽  
Author(s):  
Joseph Alexander Leines-Artieda ◽  
Chuxi Liu ◽  
Hongzhi Yang ◽  
Jianfa Wu ◽  
Cheng Chang ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
History Matching ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Unconventional Reservoirs ◽  
Production Data ◽  
Fracture Geometry ◽  
Microseismic Data ◽  
Fracture Models ◽  
Microseismic Events

Abstract Reliable estimates of hydraulic fracture geometry help reduce the uncertainty associated with estimated ultimate recovery (EUR) forecasts and optimize field developing planning in unconventional reservoirs. For these reasons, operators gather information from different sources with the objective to calibrate their hydraulic fracture models. Microseismic data is commonly acquired by operators to estimate hydraulic fracture geometry and to optimize well completion designs. However, relying solely on estimates derived from microseismic information may lead to inaccurate estimates of hydraulic fracture geometry. The objective of this study is to efficiently calibrate hydraulic fracture geometry by using microseismic data, physics-based fracture propagation models, and the embedded discrete fracture model (EDFM). We first obtain preliminary estimates of fracture geometry based on microseismic events’ spatial location and density with respect to the perforation cluster location. We then tune key completion parameters using an in-house fracture propagation model to provide hydraulic fracture geometries that are constrained by the microseismic cloud. In the history matching process, we included the effect of natural fractures, using the microseismic events location as natural fracture initiation points. Finally, we used cutoff coefficients to further reduce hydraulic fracture geometries to match production data. The results of this work showed a fast and flexible method to estimate fracture half-lengths and fracture heights, resulting in a direct indicator of the completion design. Additionally, hydraulic-natural fracture interactions were assessed. We concluded that the inclusion of cutoff coefficients as history matching parameters allows to derive realistic hydraulic and natural fracture models calibrated with microseismic and production data in unconventional reservoirs.

Sign in / Sign up

Export Citation Format

Share Document