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.

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.

The effect of gravity on the shape and direction of vertical hydraulic fractures

2020 ◽  
Vol 60 (2) ◽  
pp. 668
Author(s):  
Saeed Salimzadeh
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Gas Reservoirs ◽  
Unconventional Gas Reservoirs ◽  
Fracture Fluid ◽  
Fracture Opening

Australia has great potential for shale gas development that can reshape the future of energy in the country. Hydraulic fracturing has been proven as an efficient method to improve recovery from unconventional gas reservoirs. Shale gas hydraulic fracturing is a very complex, multi-physics process, and numerical modelling to design and predict the growth of hydraulic fractures is gaining a lot of interest around the world. The initiation and propagation direction of hydraulic fractures are controlled by in-situ rock stresses, local natural fractures and larger faults. In the propagation of vertical hydraulic fractures, the fracture footprint may extend tens to hundreds of metres, over which the in-situ stresses vary due to gravity and the weight of the rock layers. Proppants, which are added to the hydraulic fracturing fluid to retain the fracture opening after depressurisation, add additional complexity to the propagation mechanics. Proppant distribution can affect the hydraulic fracture propagation by altering the hydraulic fracture fluid viscosity and by blocking the hydraulic fracture fluid flow. In this study, the effect of gravitational forces on proppant distribution and fracture footprint in vertically oriented hydraulic fractures are investigated using a robust finite element code and the results are discussed.

scholarly journals Numerical simulation of the laws of fracture propagation of multi-hole linear co-directional hydraulic fracturing

2021 ◽  
pp. 014459872198899
Author(s):  
Weiyong Lu ◽  
Changchun He
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Minimum Principle ◽  
Fracture Propagation ◽  
Axial Direction ◽  
Rock Breaking ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Fracture Intersection ◽  
Expansion Stage

Directional rupture is one of the most important and most common problems related to rock breaking. The goal of directional rock breaking can be effectively achieved via multi-hole linear co-directional hydraulic fracturing. In this paper, the XSite software was utilized to verify the experimental results of multi-hole linear co-directional hydraulic fracturing., and its basic law is studied. The results indicate that the process of multi-hole linear co-directional hydraulic fracturing can be divided into four stages: water injection boost, hydraulic fracture initiation, and the unstable and stable propagation of hydraulic fracture. The stable expansion stage lasts longer and produces more microcracks than the unstable expansion stage. Due to the existence of the borehole-sealing device, the three-dimensional hydraulic fracture first initiates and expands along the axial direction in the bare borehole section, then extends along the axial direction in the non-bare hole section and finally expands along the axial direction in the rock mass without the borehole. The network formed by hydraulic fracture in rock is not a pure plane, but rather a curved spatial surface. The curved spatial surface passes through both the centre of the borehole and the axial direction relative to the borehole. Due to the boundary effect, the curved spatial surface goes toward the plane in which the maximum principal stress occurs. The local ground stress field is changed due to the initiation and propagation of hydraulic fractures. The propagation direction of the fractures between the fracturing boreholes will be deflected. A fracture propagation pressure that is greater than the minimum principle stress and a tension field that is induced in the leading edge of the fracture end, will aid to fracture intersection; as a result, the possibility of connecting the boreholes will increase.

Advancements in Step Down Tests to Guide Perforation Cluster Design and Limited Entry Pressure Intensities - Learnings from Field Tests in Multiple Basins

2021 ◽  
Author(s):  
Somnath Mondal ◽  
Min Zhang ◽  
Paul Huckabee ◽  
Gustavo Ugueto ◽  
Raymond Jones ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Field Tests ◽  
Pressure Drops ◽  
Wellbore Pressure ◽  
Hydraulic Fracture Propagation ◽  
Step Down ◽  
Cluster Design

Abstract This paper presents advancements in step-down-test (SDT) interpretation to better design perforation clusters. The methods provided here allow us to better estimate the pressure drop in perforations and near-wellbore tortuosity in hydraulic fracturing treatments. Data is presented from field tests from fracturing stages with different completion architectures across multiple basins including Permian Delaware, Vaca Muerta, Montney, and Utica. The sensitivity of near-wellbore pressure drops and perforation size on stimulation distribution effectiveness in plug-and-perf (PnP) treatments is modeled using a coupled hydraulic fracturing simulator. This advanced analysis of SDT data enables us to improve stimulation distribution effectiveness in multi-cluster or multiple entry completions. This analysis goes much further than the methodology presented in URTeC2019-1141 and additional examples are presented to illustrate its advantages. In a typical SDT, the injection flowrate is reduced in four or five abrupt decrements or "steps", each with a duration long enough for the rate and pressure to stabilize. The pressure-rate response is used to estimate the magnitude of perforation efficiency and near-wellbore tortuosity. In this paper, two SDTs with clean fluids were conducted in each stage - one before and another after proppant slurry was injected. SDTs were conducted in cemented single-point entry (cSPE) sleeves, which present a unique opportunity to measure only near-wellbore tortuosity using bottom-hole pressure gauge at sleeve depth, negligible perforation pressure drops, and less uncertainty in interpretation. SDTs were conducted in PnP stages in multiple unconventional basins. The results from one set of PnP stages with optic fiber distributed sensing were modeled with a hydraulic fracturing simulator that combines wellbore proppant transport, perforation size growth, near-wellbore pressure drop, and hydraulic fracture propagation. Past SDT analysis assumed that the pressure drop due to near-wellbore tortuosity is proportional to the flow rate raised to an exponent, β = 0.5, which typically overestimates perforation friction from SDTs. Theoretical derivations show that β is related to the geometry and flow type in the near-wellbore region. Results show that initial β (before proppant slurry) is typically around 0.5, but the final value of β (after proppant slurry) is approximately 1, likely due to the erosion of near-wellbore tortuosity by the proppant slurry. The new methodology incorporates the increase in β due proppant slurry erosion. Hydraulic fracturing modeling, calibrated with optic fiber data, demonstrates that the stimulation distribution effectiveness must consider the interdependence of proppant segregation in the wellbore, perforation erosion, and near-wellbore tortuosity. An improved methodology is presented to quantify the magnitude of perforation and near-wellbore tortuosity related pressure drops before and after pumping of proppant slurry in typical PnP hydraulic fracture stimulations. The workflow presented here shows how the uncertainties in the magnitude of near-wellbore complexity and perforation size, along with uncertainties in hydraulic fracture propagation parameters, can be incorporated in perforation cluster design.

Predicting Hydraulic Fracturing in a Carbonate Gas Reservoir in Abu Dhabi Using 1D Mechanical Earth Model: Uncertainty and Constraints

2015 ◽  
Author(s):  
Manhal Sirat ◽  
Mujahed Ahmed ◽  
Xing Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Abu Dhabi ◽  
Hydraulic Fractures ◽  
Gas Reservoir ◽  
In Situ Stresses ◽  
Tight Carbonate ◽  
Different Depths

Abstract In-situ stress state plays an important role in controlling fracture growth and containment in hydraulic fracturing managements. It is evident that the mechanical properties, existing stress regime and the natural fracture network of its reservoir rocks and the surrounding formations mainly control the geometry, size and containments of produced hydraulic fractures. Furthermore, the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with corresponding stress regimes at different depths. Hence predicting the hydro-fractures can be theoretically achieved once all the above data are available. This is particularly difficult in unconventional and tight carbonate reservoirs, where heterogeneity and highly stress variation, in terms of magnitude and orientation, are expected. To optimize the field development plan (FDP) of a tight carbonate gas reservoir in Abu Dhabi, 1D Mechanical Earth Models (MEMs), involving generating the three principal in-situ stresses' profiles and mechanical property characterization with depth, have been constructed for four vertical wells. The results reveal the swap of stress magnitudes at different mechanical layers, which controls the dimension and orientation of the produced hydro-fractures. Predicted containment of the Hydro-fractures within the specific zones is likely with inevitable high uncertainty when the stress contrast between Sv, SHmax with Shmin respectively as well as Young's modulus and Poisson's Ratio variations cannot be estimated accurately. The uncertainty associated with this analysis is mainly related to the lacking of the calibration of the stress profiles of the 1D MEMs with minifrac and/or XLOT data, and both mechanical and elastic properties with rock mechanic testing results. This study investigates the uncertainty in predicting hydraulic fracture containment due to lacking such calibration, which highlights that a complete suite of data, including calibration of 1D MEMs, is crucial in hydraulic fracture treatment.

Fracture Initiation and Propagation in a Deep Shale Gas Reservoir Subject to an Alternating-Fluid-Injection Hydraulic-Fracturing Treatment

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1839-1855 ◽  
Author(s):  
Bing Hou ◽  
Zhi Chang ◽  
Weineng Fu ◽  
Yeerfulati Muhadasi ◽  
Mian Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fracture Initiation ◽  
Fluid Injection ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Gas Reservoirs ◽  
Complex Fracture ◽  
Initiation And Propagation

Summary Deep shale gas reservoirs are characterized by high in-situ stresses, a high horizontal-stress difference (12 MPa), development of bedding seams and natural fractures, and stronger plasticity than shallow shale. All of these factors hinder the extension of hydraulic fractures and the formation of complex fracture networks. Conventional hydraulic-fracturing techniques (that use a single fluid, such as guar fluid or slickwater) do not account for the initiation and propagation of primary fractures and the formation of secondary fractures induced by the primary fractures. For this reason, we proposed an alternating-fluid-injection hydraulic-fracturing treatment. True triaxial hydraulic-fracturing tests were conducted on shale outcrop specimens excavated from the Shallow Silurian Longmaxi Formation to study the initiation and propagation of hydraulic fractures while the specimens were subjected to an alternating fluid injection with guar fluid and slickwater. The initiation and propagation of fractures in the specimens were monitored using an acoustic-emission (AE) system connected to a visual display. The results revealed that the guar fluid and slickwater each played a different role in hydraulic fracturing. At a high in-situ stress difference, the guar fluid tended to open the transverse fractures, whereas the slickwater tended to activate the bedding planes as a result of the temporary blocking effect of the guar fluid. On the basis of the development of fractures around the initiation point, the initiation patterns were classified into three categories: (1) transverse-fracture initiation, (2) bedding-seam initiation, and (3) natural-fracture initiation. Each of these fracture-initiation patterns had a different propagation mode. The alternating-fluid-injection treatment exploited the advantages of the two fracturing fluids to form a large complex fracture network in deep shale gas reservoirs; therefore, we concluded that this method is an efficient way to enhance the stimulated reservoir volume compared with conventional hydraulic-fracturing technologies.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

2016 ◽  
Vol 56 (1) ◽  
pp. 225 ◽  
Author(s):  
Kunakorn Pokalai ◽  
David Kulikowski ◽  
Raymond L. Johnson ◽  
Manouchehr Haghighi ◽  
Dennis Cooke
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
High Stress ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Fracture Plane ◽  
Natural Fractures ◽  
Geomechanical Model ◽  
Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Results of hydraulic fracturing design improvements and changes in execution strategies for unconventional tight gas targets in the Cooper Basin, Australia

2019 ◽  
Vol 59 (1) ◽  
pp. 244
Author(s):  
Raymond Johnson Jr ◽  
Ruizhi Zhong ◽  
Lan Nguyen
Keyword(s):  
Machine Learning ◽  
Hydraulic Fracturing ◽  
Horizontal Stress ◽  
Learning Model ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Machine Learning Model ◽  
Wellbore Pressure ◽  
Gas Targets ◽  
Cooper Basin

Tight gas stimulations in the Cooper Basin have been challenged by strike–slip to reverse stress regimes, adversely affecting the hydraulic fracturing treatment. These stress conditions increase borehole breakout and affect log and cement quality, create more tortuous pathways and near-wellbore pressure loss, and reduce fracture containment. These factors result in stimulation of lower permeability, low modulus intervals (e.g. carbonaceous shales and interbedded coals) versus targeted tight gas sands. In the Windorah Trough of the Cooper Basin, several steps have been employed in an ongoing experiment to improve hydraulic fracturing results. First, the wellbore was deviated in the maximum horizontal stress direction and perforations shot 0 to 180° phased to better align the resulting hydraulic fractures. Next, existing drilling and logging-while-drilling data were used to train a machine learning model to improve reservoir characterisation in sections with missing or poor log data. Finally, diagnostic fracture injection tests in non-pay and pay sections were targeted to specifically inform the machine learning model and better constrain permeability and stress profiles. It is envisaged that the improved well and perforation alignment and better targeting of intervals for the fracturing treatment will result in lowered tortuosity, better fracture containment, and higher concentrations of localised proppant, thereby improving conductivity and targeting of desired intervals. The authors report the process and results of their experimentation, and the results relative to the offsetting vertical well where a typical five-stage treatment was employed.

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.

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