matrix permeability
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2022 ◽  
Vol 6 (1) ◽  
pp. 54-68
Author(s):  
Jiale Zhao ◽  
Mengdi Sun ◽  
Zhejun Pan ◽  
Bo Liu ◽  
Mehdi Ostadhassan ◽  
...  

2021 ◽  
Author(s):  
Clay Kurison ◽  
Ahmed M. Hakami ◽  
Sadi H. Kuleli

Abstract Unconventional shale reservoirs are characterized by low porosity and ultra-low permeability. Natural fractures are known to be present and considered a critical factor for the enhanced post-stimulation productivity. Accounting for natural fractures with existing techniques has not been widely adopted owing to their complexity or lack of validation. Ongoing research efforts are striving to understand how natural fractures can be accounted for and accurately modeled in fluid flow of the subject reservoirs. This study utilized Eagle Ford well data comprising reservoir properties, stimulation metrics, production, microseismicity and permeability measurements from a core plug. The methodology comprised use of production data to extract a linear flow regime parameter. This was coupled with fracture geometry, predicted from hydraulic fracture modeling and microseismicity, to estimate the system permeability. From interpreting microseismic events as slips on critically stressed natural fractures, explicit modeling incorporating a discrete fracture network (DFN) assumed activated natural fractures supplement conductive reservoir contact area. Thus, allowed the estimation of matrix permeability. For validation, the aforementioned was compared with core plug permeability measurements. Results from modeling of planar hydraulic fractures, with microseismicity as validation, predicted planar fracture geometry which when coupled with the linear flow parameter resulted in a system permeability. Incorporation of DFNs to account for activated natural fractures yielded matrix permeability in picodarcy range. A review of laboratory permeability measurements exhibited stress dependence with the value at the maximum experimental confining pressure of 4000 psi in the same range as the computed system permeability. However, the confining pressures used in the experiments were less than the in situ effective stress. Correction for representative stress yielded an ultra-low matrix permeability in the same range as the DFN-based picodarcy matrix permeability. Thus, supporting the adopted drainage architecture and often suggested role of natural fractures in shale reservoir fluid flow. This study presents a multi-discipline workflow to account for natural fractures, and contributes to understanding that will improve laboratory petrophysics and the overall reservoir characterization of the subject reservoirs. Given that the Eagle Ford is an analogue of emerging shales elsewhere, results from this study can be widely adopted.


2021 ◽  
Author(s):  
Xupeng He ◽  
Marwa Alsinan ◽  
Hyung Kwak ◽  
Hussein Hoteit

Abstract Understanding the fundamental mechanism of fracture-matrix fluid exchange is crucial for the modeling of fractured reservoirs. Traditionally, high-resolution simulations for flow in fractures often neglect the matrix-fracture leakage influence on the fracture hydraulic properties, i.e., assuming impermeable fracture walls. This work introduces a micro-continuum approach to capture the matrix-fracture leakage interaction and its effect on the rock fractures’ hydraulic properties. Because of the multiscale nature of fractured media, full physics Navier-Stokes (NS) representation everywhere in the whole domain is not feasible. We thus employ NS equations to describe the flow in the fracture, and Darcy’s law to model the flow in the surrounding porous rocks. Such hybrid modeling is achieved using the extended Darcy-Brinkman-Stokes (DBS) equation. With this approach, a unified conservation equation for flow in both media is applied by choosing appropriate parameters (e.g., porosity and permeability) for the corresponding domains. We apply an accurate Mixed Finite Element approach to solve the extended DBS equation. Various sensitivity analyses are conducted to explore the leakage effects on the fracture hydraulic properties by varying surrounding matrix permeability, fracture roughness, and Reynolds number (Re). Streamline profiles show the presence of back-flow phenomena, where in-flow and out-flow are possible between the matrix and the fractures. Further, zones of stagnant (eddy) flow are observed around locations with large asperities of sharp corners under high Re conditions. Numerical results show the significant effects of roughness and inertia on flow predictions in fractures for both impermeable and leaky wall cases. Besides, the side-leakage effect can create non-uniform flow behavior within the fracture that may differ significantly from the case with impermeable wall conditions. And this matrix-fracture leakage influence on hydraulic properties of rock fractures matters especially for cases with high matrix permeability, high fracture roughness, and low Re values. In summary, we present a high-resolution micro-continuum approach to explore the flow exchange behavior between the fracture and rock matrix, and further investigate the static and dynamic effects, including variable Reynold numbers, mimicking flow near and away from the wellbore. The approach and results provide significant insights into the flow of fluids through fractures within permeable rocks and can be readily applied in field-scale reservoir simulations.


2021 ◽  
Author(s):  
Ahmed AlJanahi ◽  
Feras Altawash ◽  
Hassan AlMannai ◽  
Sayed Abdelredy ◽  
Hamed Al Ghadhban ◽  
...  

Abstract Geomechanics play an important role in stimulation design, especially in complex tight reservoirs with very low matrix permeability. Robust modelling of stresses along with rock mechanical properties helps to identify the stress barriers which are crucial for optimum stimulation design and proppant allocation. Complex modeling and calibration workflow showcased the value of geomechanical analysis in a large stimulation project in the Ostracod-Magwa reservoir, a complicated shallow carbonate reservoir in the Bahrain Field. For the initial model, regional average rock properties and minimum stress values from earlier frack campaigns were considered. During campaign progression, advanced cross dipole sonic measurements of the new wells were incorporated in the geomechanical modeling which provided rock properties and stresses with improved confidence. The outputs from wireline-conveyed microfrac tests and the fracturing treatments were also considered for calibration of the minimum horizontal stress and breakdown pressure. The porepressure variability was established with the measured formation pressure data. The geomechanically derived horizontal stresses were used as input for the frack-design. Independent fracture geometry measurements were run to validate the model. The poro-elastic horizontal strain approach was taken to model the horizontal stresses, which shows better variability of the stress profile depending on the elastic rock properties. The study shows variable depletion in porepressure across the field as well as within different reservoir layers. The Ostracod reservoir is more depleted than Magwa, with porepressure values lower than hydrostatic (∼7 ppg). The B3 shale layer in between the Magwa and Ostracod reservoirs is a competent barrier with 1200-1500psi closure pressure. The closure pressures in the Ostracod and Magwa vary from 1000-1500psi and 1100-1600psi, respectively. There is a gradual increasing trend observed in closure pressure in Magwa with depth, but no such trend is apparent in the shallower Ostracod formation. High resolution stress profiles help to identify the barriers within each reservoir to place horizontal wells and quantify the magnitude of hydraulic fracture stress barriers along horizontal wells. The geomechanical model served as a key part of the fracturing optimization workflow, resulting in more than double increase in wells productivity compared to previous stimulation campaigns. The study also helped to optimize the selection of the clusters depth of hydraulic fracturing stages in horizontal wells. The poroelastic horizontal strain approach to constrain horizontal stresses from cross dipole sonic provides better variability in the stress profile to ultimately yield high resolution. This model, calibrated with actual frac data, is crucial for stimulation design in complex reservoirs with very low matrix permeability. The geomechanical model serves as one of the few for shallow carbonates rock in the Middle East region and can be of significant importance to many other shallow projects in the region.


2021 ◽  
Author(s):  
Raphael Altman ◽  
Mariela Pichardi ◽  
Pratik Sangani ◽  
Tahani Al Rashidi ◽  
Girija Shankar Padhy ◽  
...  

Abstract The Jurassic Najmah-Sargelu of west Kuwait can be thought of as a "hybrid" between a conventional and an unconventional reservoir. These systems form an increasingly important resource for operators, but their performance is unpredictable because matrix permeability is in the micro-Darcy range and production depends on natural fractures. Success depends on how well the static models are aligned to the dynamic production, and the effectiveness of a fit-for-purpose multistage completion on project economics. In this work we present our lessons learnt in production modelling these reservoirs and the coupling between reservoir simulation and the discrete fracture network (DFN). Our reservoir models were constructed using a highly integrated approach incorporating data from all scales and disciplines (drilling, geophysical, geological, reservoir and production) and the production simulations were run using dual porosity and black oil models. As expected, the DFN played a key part of this effort. An iterative approach was used to adjust the DFN so that it was consistent with production observations. However, in all cases care was made to ensure the new DFN honoured the seismic, geological, well log and drilling data from which it was generated. Final, smaller adjustments were made to the simulation model at the log scale to match PLT data. We used uncertainty analysis to run hundreds of simulation cases and found that the character of the natural fractures is quite well imprinted in the observed production data, particularly pressure buildup data. This gave us a better understanding of whether the natural fractures are diffuse and laterally extensive away from the wellbore or if they are localized close to the wellbore. Where reservoir simulation history matches inferred laterally extensive natural fractures, an good correlation was obtained with the natural fracturing from the DFN. This correlation was poor where natural fracturing was confined to a smaller depth interval (as observed from PLT), and is a result of the limitation in seismic resolution to resolve these natural fractures. The lessons learnt from our work helps towards improved understanding of production mechanisms of these reservoirs and their natural fracture networks. This, together with higher resolution azimuthal seismic, advanced wellbore characterization data and multistage completions are the desired key ingredients for technically enhancing production in these reservoirs.


2021 ◽  
Vol 18 (6) ◽  
pp. 984-994
Author(s):  
Guangquan Li ◽  
Chaodi Xie

Abstract Previously, hydrogeologists and petroleum engineers use seepage experiments to measure permeability. This paper develops a novel method to calculate matrix permeability from velocity and attenuation of an ultrasonic S-wave. At first, permeability is derived as a function of frequency when an S-wave scans a fluid-saturated rock. Substituting the permeability into a previous S-wave model gives theoretical velocity and attenuation, in which the nexus parameter is the average distance of aperture representing pores. Fitting the predicted velocity and quality factor against the measured counterparts yields permeability in the full frequency range. For Berea sandstone, the inverted permeability at low frequency (0.0376 Darcy) is comparable to Darcy permeability (0.075 Darcy), confirming that Berea sandstone is homogenous. For Boise sandstone, the inverted permeability at low frequency is 0.0457 Darcy, much lower than Darcy permeability (1 Darcy). When S-wave scans the rocks, its velocity and attenuation are dominated by matrix pore throats and the inverted permeability represents matrix permeability. Unlike Berea sandstone, Boise sandstone has fractures and widely distributed grain diameters. The fractures and the large pores (due to large grain diameter) are preferential pathways that increase Darcy permeability far more than matrix permeability.


2021 ◽  
Author(s):  
Shuang Zheng ◽  
Mukul Sharma

Abstract Reservoir cooling during waterflooding or waste-water injection can significantly alter the reservoir stress field by thermo-poro-elastic effects. Colloidal particles in the injected water decrease the matrix permeability and buildup the injection pressure. Fractures may initiate and propagate from injectors. These fractures are of great concern for both environmental reasons and strong influence on reservoir sweep and oil recovery. This paper introduces methods to fully couple reservoir simulation with wellbore flow models in fractured injection wells. A method to fully couple reservoir-fracture-wellbore models was developed. Fluid flow, solid mechanics, energy balance, fracture propagation, and particle filtration are modelled in the reservoir, fracture and wellbore domains. Effective stress in the reservoir domain is altered by thermo-poro-elastic effects during cold water injection. Fracture initiation and propagation induced by thermal and filtration effects is modelled in the fracture domain. Particle filtration on the borehole and fracture surfaces is modelled by matrix permeability reduction and filter cake build-up. Leakoff through the borehole and fracture surface is balanced dynamically. The coupled nonlinear system of equations is solved implicitly using Newton-Raphson method. We validate our model with existing analytical solutions for simple cases. We show how the poro-elasticity effect, thermo-elasticity effect, water quality, and wellbore open/cased conditions influence well injectivity, induced fracture propagation and flow distribution. Simulation results show that water quality and thermal effects control fluid leak-off and fracture growth. While it is difficult to predict the exact location of fracture initiation due to reservoir heterogeneity, we proposed a reasonable method to handle fracture initiation without predefined fracture location in the water injection applications. In open-hole completions, this may lead to "thief" fractures propagating deep into the reservoir. Thermal stress changes in the injection zone are shown to be significant because of the combined effect of forced convection, heat conduction and poroelasticity. The accurate predictions of thermal stress in different reservoir layers allow us to study fracture height growth and containment numerically for the first time. We show that controlling the temperature and the injection water quality is also found to be an effective way to ensure fracture containment.


2021 ◽  
Author(s):  
Recep Bakar ◽  
Erdal Ozkan ◽  
Hossein Kazemi

Abstract Diagnostic fracture injection tests (DFIT) are used as an indirect method to determine closure pressure and formation effective permeability in unconventional reservoirs as a first step in formation evaluation. The information obtained from DFIT is particularly useful because it is obtained before any production for a given well is available. In DFIT, a small fracture is created by injecting few barrels of completion fluid until formation breaks down and a fracture is initiated and propagates a short distance into the reservoir. Then, injection is stopped, and the pressure decline (or falloff) is monitored. From this pressure decline, the effective permeability of the formation is estimated by Nolte's G-function, log-log plot, or square root of time analysis. In this research, the viability of the common DFIT analysis techniques was investigated for unconventional reservoirs with and without micro-fractures by using a numerical hydraulic fracturing simulator, CFRAC. The results of numerical simulations were investigated to assess the impact of permeability, residual fracture aperture, and complex fracture networks on conventional DFIT interpretations. For the example considered in this work, the commonly used G-function analysis yielded estimates of permeability over an order of magnitude higher than the simulated matrix permeability. Error in the G-function estimates of permeability were higher for higher matrix permeability and in the existence of a fracture network. On the other hand, straight-line analysis of Ap versus G-time yielded much closer (in the same order of magnitude) estimates of permeability.


2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda

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.


2021 ◽  
Author(s):  
Sebastian Ramiro-Ramirez ◽  
Peter B. Flemings ◽  
Athma R. Bhandari ◽  
Oluwafemi Solomon Jimba

Abstract We measured steady-state liquid (dodecane) permeability in four horizontal core plugs from the middle member of the Bakken Formation at multiple effective stress conditions to investigate how permeability evolves with confining stress and to infer the matrix permeability. Three of the four tested samples behaved almost perfectly elastically as the hysteresis effect was negligible. In contrast, the fourth sample showed a permeability decrease of ~40% at the end of the test program. Our interpretation is that the closure of open artificial micro-fractures initially present in the sample (based on micro-CT imaging) caused that permeability hysteresis. The matrix permeability to dodecane (oil) of the tested samples is between ~50 nD and ~520 nD at the confining pressure of 9500 psi. The 520 nD sample exhibited the lowest porosity, the highest calcite content, and the largest dominant pore throat radii. In contrast, the 50 nD sample was more porous, and exhibited the highest dolomite content and the smallest dominant pore throat radii. This study shows that our multi-stress testing protocol allows the study of the permeability hysteresis effect to interpret the matrix permeability. We also document the presence of middle Bakken lithologies with permeabilities up to one order of magnitude greater than others. These permeable lithologies may have a significant contribution to well production rates.


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