Study on the Stimulated Reservoir Volume Technology in Tight Carbonate Reservoir

2014 ◽  
Vol 1051 ◽  
pp. 77-80
Author(s):  
Heng Zheng ◽  
Ning Cheng ◽  
Zhong Wei Cao ◽  
Wen Ting Lu ◽  
Jun Sheng Sun
Keyword(s):  
Early Stage ◽  
Fracture Network ◽  
High Viscosity ◽  
Carbonate Reservoir ◽  
Form Complex ◽  
Stimulated Reservoir Volume ◽  
Continuous Type ◽  
Low Viscosity ◽  
Reservoir Volume ◽  
Tight Carbonate

In the development of carbonate reservoir, it usually uses acid fracturing to improve the production. Because of the limitation of, the production rates from the wells are very low. Based on the “stimulated reservoir volume” which is used in the development of unconventional reservoirs, combined with the characteristics of tight carbonate reservoirs, in the early stage with low viscosity liquid, large pump scheme, small size proppant and pulse type sand to form complex fracture network. In the later, with high viscosity liquid, high sand rate, large size proppant, and continuous type sand to enlarge the stimulated volume and conductivity. Based on the experimental evaluation, the fracture design was optimized, and it will provide a reference for the stimulation of tight carbonate reservoir.

Analyzing the Impacts of Meshing and Grid Alignment in Dual-Porosity Dual-Permeability Upscaling

2021 ◽  
pp. 1-20
Author(s):  
Ziming Xu ◽  
Juliana Y. Leung
Keyword(s):  
Fracture Network ◽  
Fracture Plane ◽  
Fracture Density ◽  
Shape Factors ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Multiple Length Scales ◽  
Fracture Intensity ◽  
Cumulative Production ◽  
The Difference

Summary The discrete fracture network (DFN) model is widely used to simulate and represent the complex fractures occurring over multiple length scales. However, computational constraints often necessitate that these DFN models be upscaled into a dual-porositydual-permeability (DPDK) model and discretized over a corner-point grid system, which is still commonly implemented in many commercial simulation packages. Many analytical upscaling techniques are applicable, provided that the fracture density is high, but this condition generally does not hold in most unconventional reservoir settings. A particular undesirable outcome is that connectivity between neighboring fracture cells could be erroneously removed if the fracture plane connecting the two cells is not aligned along the meshing direction. In this work, we propose a novel scheme to detect such misalignments and to adjust the DPDK fracture parameters locally, such that the proper fracture connectivity can be restored. A search subroutine is implemented to identify any diagonally adjacent cells of which the connectivity has been erroneously removed during the upscaling step. A correction scheme is implemented to facilitate a local adjustment to the shape factors in the vicinity of these two cells while ensuring the local fracture intensity remains unaffected. The results are assessed in terms of the stimulated reservoir volume calculations, and the sensitivity to fracture intensity is analyzed. The method is tested on a set of tight oil models constructed based on the Bakken Formation. Simulation results of the corrected, upscaled models are closer to those of DFN simulations. There is a noticeable improvement in the production after restoring the connectivity between those previously disconnected cells. The difference is most significant in cases with medium DFN density, where more fracture cells become disconnected after upscaling (this is also when most analytical upscaling techniques are no longer valid); in some 2D cases, up to a 22% difference in cumulative production is recorded. Ignoring the impacts of mesh discretization could result in an unintended reduction in the simulated fracture connectivity and a considerable underestimation of the cumulative production.

Is High Viscosity a Requirement for Fracturing Fluids?

2022 ◽  
Author(s):  
John E. Busteed ◽  
Jesus Arroyo ◽  
Francisco Morales ◽  
Mohammed Omer ◽  
Francisco E. Fragachan
Keyword(s):  
Injection Pressure ◽  
Fracture Network ◽  
High Viscosity ◽  
Network Simulator ◽  
Well Performance ◽  
Field Case ◽  
Temperature Conditions ◽  
Low Viscosity ◽  
Fracturing Fluids ◽  
Fracture Closure

Abstract Uniformly distributing proppant inside fractures with low damage on fracture conductivity is the most important index of successful fracturing fluids. However, due to very low proppant suspension capacity of slickwater and friction reducers fracturing fluids and longer fracture closure time in nano & pico darcies formations, proppants settles quickly and accumulates near wellbore resulting in worse-than-expected well performance, as the fracture full capacity is not open and contributing to production. Traditionally, cross-linked polymer fluid systems are capable to suspend and transport high loading of proppants into a hydraulically generated fracture. Nevertheless, amount of unbroken cross-linked polymers is usually left in fractures causing damage to fracture proppant conductivity, depending on polymer loading. To mitigate these challenges, a low viscosity-engineered-fluid with excellent proppantcarrying capacity and suspension-in excess of 30 hours at static formation temperature conditions - has been designed, enhancing proppant placement and distribution within developed fractures, with a 98% plus retained conductivity. In this work experimental and numerical tests are presented together with the path followed in developing a network of packed structures from polymer associations providing low viscosity and maximum proppant suspension. Challenges encountered during field injection with friction are discussed together with the problem understanding characterized via extensive friction loop tests. Suspension tests performed with up to 8-10 PPA of proppant concentration at temperature conditions are shared, together with slot tests performed. Physics-based model results from a 3D Discrete Fracture Network simulator that computes viscosity, and elastic parameters based on shear rate, allows to estimate pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture. This work will demonstrate the advanced capabilities and performance of the engineered fluid over conventional fracturing fluids and its benefits. Additionally, this paper will present field injection pressure analysis performed during the development of this fluid, together with a field case including production results after 8 months of treatment. The field case production decline observed after fracture treatment demonstrates the value of this system in sustaining well production and adding additional reserves.

scholarly journals APPLICATION OF FRACTAL GEOMETRY IN EVALUATION OF EFFECTIVE STIMULATED RESERVOIR VOLUME IN SHALE GAS RESERVOIRS

Fractals ◽  
2017 ◽  
Vol 25 (04) ◽  
pp. 1740007 ◽  
Author(s):  
GUANGLONG SHENG ◽  
YULIANG SU ◽  
WENDONG WANG ◽  
FARZAM JAVADPOUR ◽  
MEIRONG TANG
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fractal Geometry ◽  
Fracture Network ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Adsorbed Gas ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs

According to hydraulic-fracturing practices conducted in shale reservoirs, effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for confirming the success of hydraulic fracturing and predicting the production of hydraulic fracturing wells in shale reservoirs. However, ESRV calculation remains a longstanding challenge in hydraulic-fracturing operation. In considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), this paper introduces a fractal random-fracture-network algorithm for converting the microseismic data into fractal geometry. Five key parameters, including bifurcation direction, generating length ([Formula: see text]), deviation angle ([Formula: see text]), iteration times ([Formula: see text]) and generating rules, are proposed to quantitatively characterize fracture geometry. Furthermore, we introduce an orthogonal-fractures coupled dual-porosity-media representation elementary volume (REV) flow model to predict the volumetric flux of gas in shale reservoirs. On the basis of the migration of adsorbed gas in porous kerogen of REV with different fracture spaces, an ESRV criterion for shale reservoirs with SRV is proposed. Eventually, combining the ESRV criterion and fractal characteristic of a fracture network, we propose a new approach for evaluating ESRV in shale reservoirs. The approach has been used in the Eagle Ford shale gas reservoir, and results show that the fracture space has a measurable influence on migration of adsorbed gas. The fracture network can contribute to enhancement of the absorbed gas recovery ratio when the fracture space is less than 0.2 m. ESRV is evaluated in this paper, and results indicate that the ESRV accounts for 27.87% of the total SRV in shale gas reservoirs. This work is important and timely for evaluating fracturing effect and predicting production of hydraulic fracturing wells in shale reservoirs.

Recognition of Fracturing by Stimulated Reservoir Volume (SRV) in Shale Gas Wells

2011 ◽  
Vol 361-363 ◽  
pp. 349-352 ◽  
Author(s):  
Hui Hui Kou ◽  
Wei Dong Liu ◽  
Dong Dong Hou ◽  
Ling Hui Sun
Keyword(s):  
Fracture Network ◽  
Single Fracture ◽  
Well Performance ◽  
Stimulated Reservoir Volume ◽  
Fracture Length ◽  
Reservoir Volume ◽  
Tight Gas Sands ◽  
Well Pattern ◽  
Complex Fracture Network ◽  
Shale Reservoirs

Ultra-low permeability shale reservoir require a large fracture network to maximal well performance. In conventional reservoirs and tight gas sands, single fracture length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex fracture network are created, single fracture length and conductivity are insufficient to stimulate. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. This paper mainly illustrates perforation with interlaced row well pattern and multi-fracture fracturing technology and refracturing applied in vertical wells. Moreover, it establishes the seepage differential equation of multi-fracture.

scholarly journals Induced Seismicity and Detailed Fracture Mapping as Tools for Evaluating HDR Reservoir Volume

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2593
Author(s):  
Elżbieta Węglińska ◽  
Andrzej Leśniak
Keyword(s):  
Induced Seismicity ◽  
Fracture Network ◽  
Flowing Fluid ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Cluster Evolution ◽  
Microseismic Events ◽  
Fracture Mapping ◽  
Mass Volume ◽  
Stimulation Of

The main goal of this paper was to estimate the heat exchange rock mass volume of a hot dry rock (HDR) geothermal reservoir based on microseismicity location. There are two types of recorded microseismicity: induced by flowing fluid (wet microseismicity) and induced by stress mechanisms (dry microseismicity). In this paper, an attempt was made to extract events associated with the injected fluid flow. The authors rejected dry microseismic events with no hydraulic connection with the stimulated fracture network so as to avoid overestimating the reservoir volume. The proposed algorithm, which includes the collapsing method, automatic cluster detection, and spatiotemporal cluster evolution from the injection well, was applied to the microseismic dataset recorded during stimulation of the Soultz-sous-Forets HDR field in September 1993. The stimulated reservoir volume obtained from wet seismicity using convex hulls is approximately five times smaller than the volume obtained from the primary cloud of located events.

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.

Theoretical and Numerical Models to Predict Fracking Debonding Zone and Optimize Perforation Cluster Spacing in Layered Shale

2017 ◽  
Vol 85 (1) ◽  
Author(s):  
Tao Wang ◽  
Zhanli Liu ◽  
Yue Gao ◽  
Qinglei Zeng ◽  
Zhuo Zhuang
Keyword(s):  
Large Scale ◽  
Shear Failure ◽  
Numerical Models ◽  
Fracture Network ◽  
Dimensionless Parameters ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Bedding Planes ◽  
Two Parameters ◽  
Good Agreement

Shale is a typical layered and anisotropic material whose properties are characterized primarily by locally oriented anisotropic clay minerals and naturally formed bedding planes. The debonding of the bedding planes will greatly influence the shale fracking to form a large-scale highly permeable fracture network, named stimulated reservoir volume (SRV). In this paper, both theoretical and numerical models are developed to quantitatively predict the growth of debonding zone in layered shale under fracking, and the good agreement is obtained between the theoretical and numerical prediction results. Two dimensionless parameters are proposed to characterize the conditions of tensile and shear debonding in bedding planes. It is found that debonding is mainly caused by the shear failure of bedding planes in the actual reservoir. Then the theoretical model is applied to design the perforation cluster spacing to optimize SRV, which is important in fracking. If the spacing is too small, there will be overlapping areas of SRV and the fracking efficiency is low. If the spacing is too large, there will be stratum that cannot be stimulated. So another two dimensionless parameters are proposed to evaluate the size and efficiency of stimulating volume at the same time. By maximizing these two parameters, the optimal perforation cluster spacing and SRV can be quantitatively calculated to guide the fracking treatment design. These results are comparable with data from the field engineering.

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.

Production Characteristics Study of Tight Gas Reservoir with Network Fracturing Using Numerical Simulation

2014 ◽  
Vol 675-677 ◽  
pp. 1556-1560
Author(s):  
Guang Feng Liu ◽  
Rong Hou ◽  
Shu Sheng Li ◽  
Yan Gao ◽  
Jun Tao Wang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Physical Properties ◽  
Fracture Network ◽  
Gas Production ◽  
Tight Gas ◽  
Stimulated Reservoir Volume ◽  
Production Allocation ◽  
Reservoir Volume ◽  
Tight Gas Reservoir ◽  
Production Characteristics

Differences of physical properties between matrix and fractured region, size of fractured region and production allocation all affect production characteristics and development effect of fractured gas wells. Building a numerical simulation model of fracture network dual porosity, we studied impacts of these factors in contrast of programs of different parameters. Larger stimulated reservoir volume and higher permeability of fracture network result in good well performances but no meaningful increase in gas production when reaching a certain degree. Therefore, optimization suggestions of size and physical properties of stimulated reservoir volume as well as production allocation are proposed.

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