Consequences of rock layers and interfaces on hydraulic fracturing and well production of unconventional reservoirs

Geophysics ◽  
2018 ◽  
Vol 83 (6) ◽  
pp. MR333-MR344
Author(s):  
Seounghyun Rho ◽  
Roberto Suarez-Rivera ◽  
Samuel Noynaert
Keyword(s):  
Hydraulic Fracturing ◽  
Surface Area ◽  
Homogeneous Model ◽  
In Situ Stress ◽  
Unconventional Reservoirs ◽  
Rock Properties ◽  
Hydraulic Fractures ◽  
Shear Stresses ◽  
Principal Stresses ◽  
Well Production

Hydraulic fracturing is a fundamental condition for economic production of hydrocarbons from unconventional reservoirs. Hydrocarbon production is proportional to the propped surface area that is in contact with the reservoir and remains connected to the wellbore. Yet, the propped surface area controlling production appears to be considerably smaller than the surface area created during pumping. Somehow hydraulic fractures are disconnected, truncated, and reduced during production. One important mechanism causing this segmentation is the shear displacement of weak interfaces between rock layers. Shear stresses are generated in response to abrupt changes in material properties and changes in bed orientation, in relation to the orientation of the existing principal stresses. If the layered rocks are strongly laterally heterogeneous, they provide a high potential for shear failures and fracture segmentation along the interfaces between layers. The induced shear stress and shear slip also depend on the current geologic structure and following in situ stress loading, the stress alteration and fluid leakoff during hydraulic fracturing, and the existence of wells. We conducted numerical simulations using the finite-element method on layered and discontinuous rocks, and specifically in organic-rich mudstones and carbonate sequences. Our work was part of a field study. Three different layered rock models were simulated and compared: laterally homogeneous, laterally heterogeneous, and strongly laterally heterogeneous. For the latter, the heterogeneity was introduced by randomly varying the elastic rock properties of each layer. Our results indicate that localized shear stresses develop along interfaces between materials with contrasting properties and along the wellbore walls. This includes the generation of localized shear in planes that were principal in the homogeneous model. It was also seen that rock shear and slip, along interfaces between layers, may occur when the planes of weakness are pressurized (e.g., during hydraulic fracturing).

Geologic Controls on Gas Production and Hydraulic-Fracturing Flowback in Tight Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada

2016 ◽  
Vol 19 (01) ◽  
pp. 024-040 ◽  
Author(s):  
Liliana Zambrano ◽  
Per K. Pedersen ◽  
Roberto Aguilera
Keyword(s):  
Hydraulic Fracturing ◽  
Gas Production ◽  
Production Performance ◽  
Rock Properties ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Deep Basin ◽  
Rock Types ◽  
Sandstone Reservoirs ◽  
Geologic Controls

Summary A comparison of rock properties integrated with production performance and hydraulic-fracturing flowback (FB) of the uppermost lithostratigraphic “Monteith A” and the lowermost portion “Monteith C” of the Monteith Formation in the Western Canada Sedimentary Basin (WCSB) in Alberta is carried out with the use of existing producing gas wells. The analyses are targeted to understand the major geologic controls that differentiate the two tight gas sandstone reservoirs. This study consists of basic analytical tools available for geological characterization of tight gas reservoirs that is based on the identification and comparison of different rock types such as depositional, petrographic, and hydraulic for each lithostratigraphic unit of the Monteith Formation. As these low-matrix-permeability sandstone reservoirs were subjected to intense post-depositional diagenesis, a comparison of the various rock types allows the generation of more-accurate reservoir description, and a better understanding of the key geologic characteristics that control gas-production potential and possible impact on hydraulic-fracturing FB. Well performance and FB were the focus of many previous simulation and geochemical studies. In contrast, we find that an adequate understanding of the rocks hosting hydraulic fractures is a necessary complement to those studies for estimating FB times. This understanding was lacking in some previous studies. As a result, a new method is proposed on the basis of a crossplot of cumulative gas production vs. square root of time for estimating FB time. It is concluded that the “Monteith A” unit has better rock quality than the “Monteith C” unit because of less-heterogeneous reservoir geometry, less-complex mineralogical composition, and larger pore-throat apertures.

Digital Fracture Characterization at Hydraulic Fracturing Test Site HFTS-Midland: Fracture Clustering, Stress Effects and Lithologic Controls

2021 ◽  
Author(s):  
Debotyam Maity ◽  
Jordan Ciezobka
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Test Site ◽  
Fracture Morphology ◽  
Rock Properties ◽  
Hydraulic Fractures ◽  
Strong Positive Correlation ◽  
Fracture Roughness ◽  
Fracture Characterization ◽  
Stress Effects

Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.

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 Hydraulic Fracturing in Enhanced Geothermal Systems—Field, Tectonic and Rock Mechanics Conditions—A Review

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5725
Author(s):  
Rafał Moska ◽  
Krzysztof Labus ◽  
Piotr Kasza
Keyword(s):  
Hydraulic Fracturing ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Enhanced Geothermal Systems ◽  
Seismic Velocities ◽  
Geothermal Systems ◽  
Principal Stresses ◽  
Pumping Rate ◽  
Work Related ◽  
Stimulation Method

Hydraulic fracturing (HF) is a well-known stimulation method used to increase production from conventional and unconventional hydrocarbon reservoirs. In recent years, HF has been widely used in Enhanced Geothermal Systems (EGS). HF in EGS is used to create a geothermal collector in impermeable or poor-permeable hot rocks (HDR) at a depth formation. Artificially created fracture network in the collector allows for force the flow of technological fluid in a loop between at least two wells (injector and producer). Fluid heats up in the collector, then is pumped to the surface. Thermal energy is used to drive turbines generating electricity. This paper is a compilation of selected data from 10 major world’s EGS projects and provides an overview of the basic elements needed to design HF. Authors were focused on two types of data: geological, i.e., stratigraphy, lithology, target zone deposition depth and temperature; geophysical, i.e., the tectonic regime at the site, magnitudes of the principal stresses, elastic parameters of rocks and the seismic velocities. For each of the EGS areas, the scope of work related to HF processes was briefly presented. The most important HF parameters are cited, i.e., fracturing pressure, pumping rate and used fracking fluids and proppants. In a few cases, the dimensions of the modeled or created hydraulic fractures are also provided. Additionally, the current state of the conceptual work of EGS projects in Poland is also briefly presented.

3D Extended Finite Element Modeling of Hydraulic Fracturing Design and Operation in Shale Gas Reservoir and Validation with Micro-Seismicity Data

2021 ◽  
Author(s):  
Ikhwanul Hafizi Musa ◽  
Junghun Leem ◽  
Chee Phuat Tan ◽  
M Fakharuddin Che Yusoff
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Hydraulic Fracture ◽  
Treatment Plan ◽  
Rock Properties ◽  
Future Application ◽  
Hydraulic Fractures ◽  
Stress Shadow ◽  
Gas Formation ◽  
Wellbore Pressure

Abstract Hydraulic fracturing is vital in unconventional shale gas development in order to produce economically from the reservoir. An optimum hydraulic fracturing design and operation can be the key difference between good and poor producing well and economics of the well. One of the most common hydraulic fracturing designs is ball drop system. Using ABAQUS software with XFEM method, a three layers model is used to represent overburden formation, shale gas formation and underburden formation. Rock properties, pore pressure and stress data are used as inputs for the generated model. A horizontal well is created in the middle shale gas formation with three fracture stages and 100m perforation spacing between them. Each hydraulic fracture stage is pressurized sequentially based on the treatment plan of ball drop sliding sleeve completion. The simulated hydraulic fractures are evaluated and compared with the measured field data. The comparison of the average wellbore pressure is good as they all showed within 10% of the measured data. The comparison of the hydraulic fracture geometry with the micro-seismicity data is reasonable overall in view of the data evaluation showing considerable uncertainties in the data. The hydraulic fracturing results also show that at 100m perforation spacing and using sequential hydraulic fracturing method (such as ball drop system), the effect of stress shadow is minimal and does not inhibit the fractures growth. However, the stress shadow effect is found to be pronounced for closer spacing between hydraulic fractures. For future application of the developed XFEM hydraulic fracturing model, it can be utilized to design new hydraulic fracturing completion in order to recommend the optimum completion, including perforation spacing, of development wells in unconventional shale gas field.

Influence of Finite Hydraulic-Fracture Conductivity on Unconventional Hydrocarbon Recovery With Horizontal Wells

SPE Journal ◽  
2017 ◽  
Vol 22 (06) ◽  
pp. 1790-1807 ◽  
Author(s):  
Deming Mao ◽  
David S. Miller ◽  
John M. Karanikas ◽  
Ed A. Lake ◽  
Phillip S. Fair ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Normal Derivative ◽  
Unconventional Reservoirs ◽  
Analytical Models ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Hydraulic Stimulation ◽  
Fracture Conductivity ◽  
Hydrocarbon Recovery

Summary The classic plots of dimensionless fracture conductivity (CfD) vs. equivalent wellbore radius or equivalent negative skin are useful for evaluating the performance of hydraulic fractures (HFs) in vertical wells targeting conventional reservoirs (Prats 1961; Cinco-Ley and Samaniego-V. 1981). The increase in well productivity after hydraulic stimulation can be estimated from the “after fracturing” effective wellbore radius or from the “after fracturing” equivalent negative skin. However, this earlier work does not apply to the case of horizontal wells with multiple fractures. A revision of the diagnostic plots is needed to account for the combination of the resulting radial-flow regime and the transient effect in unconventional reservoirs with ultralow permeability. This paper reviews and extends this earlier work with the objective of making it applicable in the case of horizontal wells with multiple fractures. It also demonstrates practical application of this new technique for fracture-design optimization for horizontal wells. The influence of finite fracture conductivity (FC) on the HF flow efficiency is evaluated through analytical models, and it is confirmed by a 3D transient numerical-reservoir simulation. This work demonstrates that a redefined dimensionless fracture conductivity for horizontal wells CfD,h = 4 is found to be optimal by use of the maximum of log-normal derivative (subject to economics) for HFs in horizontal wells, and this value of CfD,h can provide 50% of the fracture-flow efficiency and 90% of the estimated ultimate recovery (EUR) that would have been obtained from an infinitely conductive fracture for the same production period. This new master plot can provide guidance for hydraulic-fracturing design and its optimization for hydrocarbon recovery in unconventional reservoirs through hydraulic fracturing in horizontal wells.

scholarly journals High-Resolution Imaging of the ML 2.9 August 2019 Earthquake in Lancashire, United Kingdom, Induced by Hydraulic Fracturing during Preston New Road PNR-2 Operations

2020 ◽  
Vol 92 (1) ◽  
pp. 151-169 ◽  
Author(s):  
Tom Kettlety ◽  
James P. Verdon ◽  
Antony Butcher ◽  
Matthew Hampson ◽  
Lucy Craddock
Keyword(s):  
United Kingdom ◽  
Stress Field ◽  
Hydraulic Fracturing ◽  
B Value ◽  
In Situ Stress ◽  
Mitigation Strategies ◽  
Hydraulic Fractures ◽  
Rupture Area ◽  
United Kingdom Government ◽  
Downhole Array

Abstract Hydraulic fracturing (HF) at Preston New Road (PNR), Lancashire, United Kingdom, in August 2019, induced a number of felt earthquakes. The largest event (ML 2.9) occurred on 26 August 2019, approximately three days after HF operations at the site had stopped. Following this, in November 2019, the United Kingdom Government announced a moratorium on HF for shale gas in England. Here we provide an analysis of the microseismic observations made during this case of HF-induced fault activation. More than 55,000 microseismic events were detected during operations using a downhole array, the vast majority measuring less than Mw 0. Event locations revealed the growth of hydraulic fractures and their interaction with several preexisting structures. The spatiotemporal distribution of events suggests that a hydraulic pathway was created between the injection points and a nearby northwest–southeast-striking fault, on which the largest events occurred. The aftershocks of the ML 2.9 event clearly delineate the rupture plane, with their spatial distribution forming a halo of activity around the mainshock rupture area. Across clusters of events, the magnitude distributions are distinctly bimodal, with a lower Gutenberg–Richter b-value for events above Mw 0, suggesting a break in scaling between events associated with hydraulic fracture propagation, and events associated with activation of the fault. This poses a challenge for mitigation strategies that rely on extrapolating microseismicity observed during injection to forecast future behavior. The activated fault was well oriented for failure in the regional stress field, significantly more so than the fault activated during previous operations at PNR in 2018. The differing orientations within the stress field likely explain why this PNR-2 fault produced larger events compared with the 2018 sequence, despite receiving a smaller volume of injected fluid. This indicates that fault orientation and in situ stress conditions play a key role in controlling the severity of seismicity induced by HF.

scholarly journals Experimental and Numerical Investigation on Basic Law of Dense Linear Multihole Directional Hydraulic Fracturing

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Xin Zhang ◽  
Yuqi Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Large Scale ◽  
Pore Water Pressure ◽  
Water Pressure ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Basic Law

Using the dense linear multihole to control the directional hydraulic fracturing is a significant technical method to realize roof control in mining engineering. By combining the large-scale true triaxial directional hydraulic fracturing experiment with the discrete element numerical simulation experiment, the basic law of dense linear holes controlling directional hydraulic fracturing was studied. The results show the following: (1) Using the dense linear holes to control directional hydraulic fracturing can effectively form directional hydraulic fractures extending along the borehole line. (2) The hydraulic fracturing simulation program is very suitable for studying the basic law of directional hydraulic fracturing. (3) The reason why the hydraulic fracture can be controlled and oriented is that firstly, due to the mutual compression between the dense holes, the maximum effective tangential tensile stress appears on the connecting line of the drilling hole, where the hydraulic fracture is easy to be initiated. Secondly, due to the effect of pore water pressure, the disturbed stress zone appears at the tip of the hydraulic fracture, and the stress concentration zone overlaps with each other to form the stress guiding strip, which controls the propagation and formation of directional hydraulic fractures. (4) The angle between the drilling line and the direction of the maximum principal stress, the in situ stress, and the hole spacing has significant effects on the directional hydraulic fracturing effect. The smaller the angle, the difference of the in situ stress, and the hole spacing, the better the directional hydraulic fracturing effect. (5) The directional effect of synchronous hydraulic fracturing is better than that of sequential hydraulic fracturing. (6) According to the multihole linear codirectional hydraulic fracturing experiments, five typical directional hydraulic fracture propagation modes are summarized.

Workflow to Optimize Cluster Spacing Design of Horizontal Multistage Fractured Well in Unconventional Source Rock

2021 ◽  
Author(s):  
Rabah Mesdour ◽  
Moemen Abdelrahman ◽  
Abdulbari Alhayaf
Keyword(s):  
Hydraulic Fracturing ◽  
Source Rock ◽  
Unconventional Reservoirs ◽  
Analytical Models ◽  
Sensitivity Analyses ◽  
Reservoir Modeling ◽  
Hydraulic Fractures ◽  
Reservoir Model ◽  
Well Productivity ◽  
Horizontal Drilling

Abstract Horizontal drilling and multistage hydraulic fracturing applied in unconventional reservoirs over the past decade to create a large fracture surface area to improve the well productivity. The combination of reservoir quality with perforation cluster spacing and fracture staging are keys to successful hydraulic fracturing treatment for horizontal wells. The objective of this work is to build and calibrate a dynamic model by integrating geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a horizontal well drilled in the source rock reservoir using simulation and analytical models. The methodology adopted in this study covers the integration of geological, petrophysical, and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and the perforation clusters number required within a frac stage. Assuming all perforation clusters are uniformly distributed within a stage. The hydraulic planer fracture attributes assumed and the surface production measurement together with the production profile were used to calibrate the reservoir model. The properties of the Stimulated Reservoir Volume "SRV" were defined after the final calibration using reservoir model including hydraulic fractures. The calibrated reservoir model was used to carry out sensitivity analyses for cluster spacing optimization and other completion parameters considering the surface and reservoir constraints. An optimum cluster spacing was observed based on the Estimated Ultimate Recovery "EUR" of the subject well by reservoir properties. The final results based on 70% of perforation clusters contribution to production observed from PLT log, and the results of this study were implemented. Afterwards, another study has been undertaken to increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity as an area for improvement to engineering the completion design. The methodology adopted in this study identifies the most important parameters of completion affecting well productivity for specific unconventional reservoirs. This study will help to engineer completion design, improve cluster efficiency, reduce cost and increase well EUR for the development phase.

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