scholarly journals Measuring hydraulic fracture apertures: a comparison of methods

Solid Earth ◽  
2020 ◽  
Vol 11 (6) ◽  
pp. 2411-2423
Author(s):  
Chaojie Cheng ◽  
Sina Hale ◽  
Harald Milsch ◽  
Philipp Blum
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Transport ◽  
Fractured Rock ◽  
Quantitative Agreement ◽  
Repeated Measurements ◽  
Mechanical Fracture ◽  
Fracture Width ◽  
Matrix Permeability ◽  
Flow Through ◽  
Fracture Apertures

Abstract. Hydraulic fracture apertures predominantly control fluid transport in fractured rock masses. Hence, the objective of the current study is to investigate and compare three different laboratory-scale methods to determine hydraulic apertures in fractured (Fontainebleau and Flechtinger) sandstone samples with negligible matrix permeability. Direct measurements were performed by using a flow-through apparatus and a transient-airflow permeameter. In addition, a microscope camera permitted measuring the mechanical fracture apertures from which the corresponding hydraulic apertures were indirectly derived by applying various empirical correlations. Single fractures in the sample cores were generated artificially either by axial splitting or by a saw cut resulting in hydraulic apertures that ranged between 8 and 66 µm. Hydraulic apertures, accurately determined by the flow-through apparatus, are used to compare results obtained by the other methods. The transient-airflow permeameter delivers accurate values, particularly when repeated measurements along the full fracture width are performed. In this case, the derived mean hydraulic fracture apertures are in excellent quantitative agreement. When hydraulic apertures are calculated indirectly from optically determined mechanical apertures using empirical equations, they show larger variations that are difficult to compare with the flow-through-derived results. Variations in hydraulic apertures as observed between methods are almost certainly related to differences in sampled fracture volume. Overall, using direct flow-through measurements as a reference, this study demonstrates the applicability of portable methods to determine hydraulic fracture apertures at both the laboratory and outcrop scales.

scholarly journals Measuring hydraulic fracture apertures: a comparison of methods

2020 ◽  
Author(s):  
Chaojie Cheng ◽  
Sina Hale ◽  
Harald Milsch ◽  
Philipp Blum
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Transport ◽  
Fractured Rock ◽  
Quantitative Agreement ◽  
Repeated Measurements ◽  
Mechanical Fracture ◽  
Fracture Width ◽  
Matrix Permeability ◽  
Flow Through ◽  
Fracture Apertures

Abstract. Hydraulic fracture apertures predominantly control fluid transport in fractured rock masses. Hence, the objective of the current study is to investigate and compare three different laboratory scale methods to determine hydraulic apertures in fractured (Fontainebleau and Flechtinger) sandstone samples with negligible matrix permeability. Direct measurements were performed by using a flow-through apparatus and a transient-airflow permeameter. In addition, a microscope camera permitted to measure the mechanical fracture apertures from which the corresponding hydraulic apertures were indirectly derived by applying various empirical correlations. Single fractures in the sample cores were generated artificially either by axial splitting or by a saw cut resulting in hydraulic apertures that ranged between 8 μm and 66 μm. The transient-airflow permeameter shows accurate values in comparison to the flow-through derived results, in particular when repeated measurements along the full fracture width are performed. In this case, the derived hydraulic fracture apertures are in an excellent quantitative agreement. When hydraulic apertures are calculated indirectly from optically determined mechanical apertures using empirical equations, aperture differences between samples are merely reproduced qualitatively. Variations in hydraulic apertures as observed between methods are almost certainly related to differences in sampled fracture volume. Overall, using direct flow-through measurements as a reference, this study demonstrates the applicability of mobile methods to determine hydraulic fracture apertures at both the laboratory and outcrop scales.

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

Simulation of Fluid Flow through a Hydraulic Fracture of a Heterogeneous Fracture-Tough Reservoir in the Planar 3D Formulation

2021 ◽  
Vol 56 (2) ◽  
pp. 164-177
Author(s):  
A. B. Kiselev ◽  
Li Kay-Zhui ◽  
N. N. Smirnov ◽  
D. A. Pestov
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Flow Through

Advanced Modeling Capability to Enhance Near-Wellbore and Far-Field Bridging in Acid Fracturing Field Treatments

2021 ◽  
Author(s):  
Abdul Muqtadir Khan ◽  
Denis Emelyanov ◽  
Rostislav Romanovskii ◽  
Olga Nevvonen
Keyword(s):  
High Resolution ◽  
Fluid Transport ◽  
Field Studies ◽  
Particulate Material ◽  
Injection Rate ◽  
Far Field ◽  
Field Scale ◽  
Fracture Width ◽  
Acid Fracturing ◽  
Modeling Approach

Abstract Different applications of fracture bridging and diversion are used regularly in carbonate acid fracturing without an in-depth understanding of the physical phenomena that dominate the processes involved in the bridging and diversion process. The extension of modeling capabilities in conjunction with yard-scale and field-scale experiences will increase our understanding of these processes. A robust multimodal diversion pill and polylactic acid fiber-laden viscous acid were utilized for near-wellbore and far-field bridging, respectively. Numerous field treatments demonstrated the uncertainty of achieving effective diversion. An existing multiphysics model was extended to develop functionalities to model diversions at different scale. Extensive laboratory testing was conducted to understand the scale of bridging and diversion mechanisms. Finally, a bridging yard test was designed, and field case studies were used to integrate all the branches. Field cases showed a diversion pressure up to 4,000 psi depending on perforation strategy, pill volume, and pill seating rate. Correlations showed the interdependence of multiple parameters in diversion processes. The field studies motivated modeling capabilities to simulate the critical diversion processes at high resolution and quality. The model simulates diverting agents that reduce leakoff in the fracture area and their effects on fracture geometry. The approach considers the acid reaction kinetics coupled with geomechanics and fluid transport. Different diverting agent concentrations required for bridging can be modeled effectively. A yard test was designed to confirm the integrity of the pill material through completion valves (minimum inside diameter 9.5 mm) and analyzed with high-resolution imaging. All the theoretical, mathematical, and numerical findings from modeling were integrated with laboratory- and yard-scale experimentation results to develop and validate near-wellbore and far-field diversion modeling. Analytical correlations were formulated from injection rate, particulate material concentration, pill volumes, fracture width, etc., to incorporate and validate the model. This study enhances understanding of the different diversion mechanisms from high-fidelity theoretical modeling approach integrated with a practical experimental view at laboratory and field scale. Current comprehensive research has significant potential to make the modeling approach a reliable method to develop tight carbonate formations around the globe.

scholarly journals Improved Method for Measuring the Permeability of Nanoporous Material and Its Application to Shale Matrix with Ultra-Low Permeability

Materials ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1567 ◽  
Author(s):  
Taojie Lu ◽  
Ruina Xu ◽  
Bo Zhou ◽  
Yichuan Wang ◽  
Fuzhen Zhang ◽  
...  
Keyword(s):  
High Pressure ◽  
Fluid Transport ◽  
Effective Means ◽  
Clean Energy ◽  
Nanoporous Materials ◽  
Environmental Research ◽  
Low Permeability ◽  
Matrix Permeability ◽  
Wide Range ◽  
The Matrix

Nanoporous materials have a wide range of applications in clean energy and environmental research. The permeability of nanoporous materials is low, which affects the fluid transport behavior inside the nanopores and thus also affects the performance of technologies based on such materials. For example, during the development of shale gas resources, the permeability of the shale matrix is normally lower than 10−3 mD and has an important influence on rock parameters. It is challenging to measure small pressure changes accurately under high pressure. Although the pressure decay method provides an effective means for the measurement of low permeability, most apparatuses and experiments have difficulty measuring permeability in high pressure conditions over 1.38 MPa. Here, we propose an improved experimental method for the measurement of low permeability. To overcome the challenge of measuring small changes in pressure at high pressure, a pressure difference sensor is used. By improving the constant temperature accuracy and reducing the helium leakage rate, we measure shale matrix permeabilities ranging from 0.05 to 2 nD at pore pressures of up to 8 MPa, with good repeatability and sample mass irrelevance. The results show that porosity, pore pressure, and moisture conditions influence the matrix permeability. The permeability of moist shale is lower than that of dry shale, since water blocks some of the nanopores.

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