What are the Dominant Flow Regimes During Carbon Dioxide Propagation in Shale Reservoirs’ Matrix, Natural Fractures and Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Viscous Flow ◽  
Flow Regime ◽  
Knudsen Diffusion ◽  
Flow Regimes ◽  
Hydraulic Fractures ◽  
Transition Flow ◽  
Pore Sizes ◽  
Thermodynamic Conditions ◽  
Shale Reservoirs

Abstract Carbon dioxide (CO2) injection in low permeability shale reservoirs has recently gained much attention due to the claims that it has a large recovery factor and can also be used in CO2 storage operations. This research investigates the different flow regimes that the CO2 will exhibit during its propagation through the fractures, micropores, and the nanopores in unconventional shale reservoirs to accurately evaluate the mechanism by which CO2 recovers oil from these reservoirs. One of the most widely used tools to distinguish between different flow regimes is the Knudsen Number. Initially, a mathematical analysis of the different flow regimes that can be observed in pore sizes ranging between 0.2 nanometer and more than 2 micrometers was undergone at different pressure and temperature conditions to distinguish between the different flow regimes that the CO2 will exhibit in the different pore sizes. Based on the results, several flow regime maps were conducted for different pore sizes. The pore sizes were grouped together in separate maps based on the flow regimes exhibited at different thermodynamic conditions. Based on the results, it was found that Knudsen diffusion dominated the flow regime in nanopores ranging between 0.2 nanometers, up to 1 nanometer. Pore sizes between 2 and 10 nanometers were dominated by both a transition flow, and slip flow. At 25 nanometer, and up to 100 nanometers, three flow regimes can be observed, including gas slippage flow, transition flow, and viscous flow. When the pore size reached 150 nanometers, Knudsen diffusion and transition flow disappeared, and the slippage and viscous flow regimes were dominant. At pore sizes above one micrometer, the flow was viscous for all thermodynamic conditions. This indicated that in the larger pore sizes the flow will be mainly viscous flow, which is usually modeled using Darcy's law, while in the extremely small pore sizes the dominating flow regime is Knudsen diffusion, which can be modeled using Knudsen's Diffusion law or in cases where surface diffusion is dominant, Fick's law of diffusion can be applied. The mechanism by which the CO2 improves recovery in unconventional shale reservoirs is not fully understood to this date, which is the main reason why this process has proven successful in some shale plays, and failed in others. This research studies the flow behavior of the CO2 in the different features that could be present in the shale reservoir to illustrate the mechanism by which oil recovery can be increased.

Parallel-Simulator Framework for Multipermeability Modeling With Discrete Fractures for Unconventional and Tight Gas Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1370-1385 ◽  
Author(s):  
Larry S. Fung ◽  
Shouhong Du
Keyword(s):  
Organic Matter ◽  
Transient Flow ◽  
Domain Decomposition Method ◽  
Knudsen Diffusion ◽  
Fracture Network ◽  
Simulation System ◽  
Hydraulic Fractures ◽  
Mathematical Framework ◽  
Fine Grid ◽  
Shale Reservoirs

Summary Economic gas rate from ultralow-permeability shale reservoirs requires the creation of a complex fracture network in a large volume known as the stimulated reservoir volume (SRV). The fracture network connects a large surface area of the reservoir to the well. It is created by injecting low-viscosity fracturing fluid (slickwater) at very high rates in multiple stages along the horizontal wellbore. Numerical simulation is used to evaluate the stimulation designs and completion strategy. Microseismic (MS) -survey fracture mapping can provide a measurement of the overall SRV and an estimate of the fracture patterns. Special core analyses provide estimates of shale-matrix permeability. The extent of the fracture network indicates that there is insufficient proppant volume, and many stimulated fractures may be only partially propped or may be unpropped. Thus, fracture conductivity will vary spatially caused by uneven proppant distribution and temporally caused by stress sensitivity upon pressure decline during production. Because of the vast contrast in conductivity between stimulated/hydraulic fractures (darcy-ft) and shale matrix (nd-ft), the transient response in matrix/fracture flow cannot be captured accurately if the stimulated fractures are approximated with large dual-continuum (DC) gridblocks. The gridding requirement to achieve an accurate solution in fractured shale reservoirs is investigated and discussed. In this work, the stimulated and hydraulic fractures are discretized explicitly to form a discrete fracture network (DFN). This paper discusses the mathematical framework and parallel numerical methods for simulating unconventional reservoirs. The simulation methods incorporate known mechanisms and processes for shale, which include gas sorption in organic matter; combined Knudsen diffusion and viscous flow in nanopores; stress-sensitive fracture permeability; and velocity-dependent flow in the high-conductivity hydraulic fractures. The simulation system is based on a general finite-volume method that includes a multiconnected multicontinuum (MC) representation of the pore system with either a compositional or a black-oil fluid description. The MC model is used to represent the storage and intercommunication among the various porosities in shale (organic matter, inorganic matter, fine unstimulated natural fractures). Unconventional simulation involves many more nonlinearities, and the extreme contrast in permeabilities will make the problems harder to solve. We discuss numerical implementation of the methods for modeling the mechanisms and processes in fractured shale. In addition, we discuss the MC formulation, the discretization method, the unstructured parallel domain-decomposition method, and the solution method for the simulation system. Finally, we explain our efforts in numerical validation of the system with fine-grid single-porosity simulation. We show numerical examples to demonstrate the applications of the simulator and to study the transient flow behavior in shale reservoirs. The effects of the various mechanisms for gas production are also evaluated.

Will Carbon Dioxide Injection in Shale Reservoirs Produce from the Shale Matrix, Natural Fractures, or Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Co2 Injection ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Recovery Potential ◽  
Shale Reservoirs ◽  
The Impact

Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.

Role of Turbulent Flow in Generating Short Hydraulic Fractures with High Net Pressure in Slickwater Treatments

2015 ◽  
Author(s):  
Brandon C. Ames ◽  
Andrew P. Bunger
Keyword(s):  
Fluid Flow ◽  
Turbulent Flow ◽  
Flow Regime ◽  
Flow Model ◽  
High Rate ◽  
Hydraulic Fractures ◽  
Fracture Length ◽  
Wellbore Pressure ◽  
Net Pressure ◽  
Shale Reservoirs

Abstract This paper provides an argument for considering turbulent flow for hydraulic fracturing using slickwater in shale reservoirs. It shows that the tendency of models that assume laminar fluid flow to over-predict fracture length and under-predict net pressure can be corrected by instead recognizing that the flow regime is turbulent for high rate, water-driven hydraulic fractures. Firstly, we provide a rationale supporting the appropriateness of assuming turbulent flow. Then, using a Perkins-Kern-Nordgren (PKN) fracture model and parameters similar to slickwater treatments in shale reservoirs, we show that the laminar flow model overpredicts fracture length and underpredicts fracture width and net pressure, compared to the turbulent flow model. The result, if indeed a hydraulic fracture grows in the turbulent fluid flow regime, is that matching the length with the laminar model requires input of an unreasonably large leak-off coefficient, resulting in an exacerbation of the underprediction of the wellbore pressure. On the other hand, the turbulent model is shown to be able, in principle, to account for short, high pressure hydraulic fractures without resorting to inflating the leak-off coefficient or compromising the calibration of the model to the wellbore pressure.

The influences of bathymetry and flow regime upon the morphology of sublittoral sponge communities

2000 ◽  
Vol 80 (4) ◽  
pp. 707-718 ◽  
Author(s):  
James J. Bell ◽  
David K.A. Barnes
Keyword(s):  
Turbulent Flow ◽  
Flow Regime ◽  
Current Flow ◽  
Volume Ratio ◽  
Basal Area ◽  
Morphological Diversity ◽  
Flow Regimes ◽  
High Energy ◽  
Similarity Analysis ◽  
Lough Hyne

Sponge communities were sampled at 3 m depth intervals at six sites experiencing different flow regimes at Lough Hyne, Ireland. Sponges were identified and classified within the following morphological groups: encrusting, massive, globular, pedunculate, tubular, flabellate, arborescent, repent and papillate morphological types on both vertical (≈90°) and inclined (≈45°) surfaces.Differences in the proportional abundance of the sponge body forms and density (sponge m−2) were observed between sites and depths. The density of sponges increased with depth at sites of slight to moderate current flow, but not at the site where current flow was turbulent. Morphological diversity of sponge communities decreased with increasing current flow due to the removal of delicate forms such as pedunculate and arborescent shaped sponges. Massive and encrusting morphologies dominated at the high-energy sites (fast and turbulent flow regimes) due to a high basal area to volume ratio, which prevents removal from cliff surfaces. However, pedunculate, papillate and arborescent types dominated at the low current sites as these shapes may help to prevent the settlement of sediment on sponge surfaces. Bray–Curtis Similarity analysis and Correspondence Analysis were used to distinguish between five different morphological communities.

Optimum thermodynamic conditions for upper pressure limits of transcritical carbon dioxide refrigeration cycle

2010 ◽  
Vol 33 (7) ◽  
pp. 1395-1401 ◽  
Author(s):  
K. Srinivasan ◽  
P. Sheahen ◽  
C.S.P. Sarathy
Keyword(s):  
Carbon Dioxide ◽  
Refrigeration Cycle ◽  
Thermodynamic Conditions ◽  
Transcritical Carbon Dioxide

Effects of Pore Sizes on Dissociation Temperatures and Pressures of Methane, Carbon Dioxide, and Propane Hydrates in Porous Media

2002 ◽  
Vol 106 (4) ◽  
pp. 820-826 ◽  
Author(s):  
Tsutomu Uchida ◽  
Takao Ebinuma ◽  
Satoshi Takeya ◽  
Jiro Nagao ◽  
Hideo Narita
Keyword(s):  
Carbon Dioxide ◽  
Porous Media ◽  
Pore Sizes ◽  
Methane Carbon

Flow and Energy Loss Downstream of Rectangular Sharp-Crested Weirs for Free and Submerged Flows

2021 ◽  
Author(s):  
Mahmud R. Amin ◽  
Nallamuthu Rajaratnam ◽  
David Z. Zhu
Keyword(s):  
Energy Loss ◽  
Flow Regime ◽  
Analytical Study ◽  
Flow Characteristics ◽  
Turbulent Jets ◽  
Flow Regimes ◽  
Impinging Jet ◽  
Relative Energy ◽  
Surface Flow ◽  
Upper Stage

Abstract This work presents an analytical study of the flow and energy loss immediately downstream of rectangular sharp-crested weirs for free and submerged flows, using the theory of plane turbulent jets and the analysis of some relevant studies. The flow regimes downstream of the sharp-crested weir is characterized as the impinging jet and surface flow regimes. Based on the flow characteristics and the downstream tailwater depths, each flow regime is further classified, and the relative energy loss equation is developed. It is found that significant energy loss occurs for the regime of supercritical flow and the upper stage of impinging jet flow. The energy loss for the submerged flow regime is minimal.

Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs

2015 ◽  
Vol 18 (02) ◽  
pp. 187-204 ◽  
Author(s):  
Fikri Kuchuk ◽  
Denis Biryukov
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Fractured Reservoir ◽  
Pressure Transient ◽  
Matrix Block ◽  
Naturally Fractured

Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.

Unstable Two-Fluid Flow in a Porous Medium

1969 ◽  
Vol 9 (03) ◽  
pp. 293-300 ◽  
Author(s):  
J.E. Varnon ◽  
R.A. Greenkorn
Keyword(s):  
Porous Medium ◽  
Fluid Flow ◽  
Flow Regime ◽  
Flow Regimes ◽  
Gravity Force ◽  
Unstable Flow ◽  
Stable Regime ◽  
Viscous Forces ◽  
Finger Width ◽  
Two Fluid

Abstract This paper reports an investigation of unstable fingering in two-fluid flow in a porous medium to determine if lambda the dimensionless finger width, is unique For a viscous finger A is the ratio of finger width to the distance between the tips of the two trailing fingers adjacent to the leading finger. For a gravity finger lambda is defined as the ratio of finger width, to "height" of the medium perpendicular to hulk flow. This work confirms previous experiments and existing theory that for viscous fingering lambda approaches a value of 0.5 with increasing ratio of viscous to interfacial force. However, for a given fluid pair and given, medium, this ratio can he increased only by increasing the, velocity. Experiments on gas liquid systems show that the asymptotic value of lambda with velocity is not always 0.5. Apparently, for gas-liquid systems, the influence of the interfacial force cannot always he eliminated by increasing the velocity. For such systems lambda is a function of fluid pair and media permeability. If the gravity force normal to the hulk permeability. If the gravity force normal to the hulk flow is active, it damps out the viscous fingers except for an underlying or overlying finger. The dimensionless width of this gravity finger strongly depends on velocity and height of the medium, as well as the fluid and media properties. The existing experiments and theories are reviewed and the gravity, stable, and viscous flow regimes are described in view of these experiments and theories. The existence of a gravity-dominated unstable regime, a gravity-viscous balanced stable regime, and a viscous-anminated regime was demonstrated experimentally by increasing flow velocity bin a rectangular glass head model. Asymptotic values of the dimensionless finger width were determined in various-sized Hele-Shaw models with gravity perpendicular and parallel to flow. The dimensionless perpendicular and parallel to flow. The dimensionless finger width lambda was determined as a function of applied force, flow resistance, and fluid properties. The results are interpreted dimensionally. Some comments are made concerning possible scaling and meaningful extensions of theory to describe these regimes in three-dimensional flow. Previous description of unstable two-fluid flow in porous media is mainly restricted to studies of viscous-dominated instability. The direction of this study is to provide data and understanding to consider the more realistic problem of predicting flow in three dimensions that may result in instabilities that are combinations of all, four flow regimes. Introduction The unstable flow of two fluids is characterized by interface changes between the fluids as a result of changes in relative forces. In a given porous medium and for a given fluid pair the gravity force dominates flow at low displacement velocities. As the velocity increases the viscous forces begin to affect flow significantly, and eventually there is a balance between effects of the gravity and viscous forces. As velocity increases further, the viscous force dominates flow. In the plane parallel to gravity, four flow regimes result as the velocity is increased: a gravity-induced stable flow regime; a gravity-dominated unstable flow regime; a stable regime resulting from a balance between gravity and viscous forces; and a viscous-induced unstable flow regime. The gravity-induced stable regime is represented schematically in Fig. 1a. This general flow pattern persists with the displacing fluid contacting all of persists with the displacing fluid contacting all of the in-place fluid until the interface becomes parallel to the bulk flow. At this velocity a gravity finger forms, and the interface, is unstable in that the length of the gravity finger grows and the fluid behind the nose of the finger is practically nonmobile because of the small pressure gradient along the finger. The gravity-dominated unstable flow is shown schematically in Fig. 1b. As the injection rate is increased, the gravity finger thickens, perhaps until it spans the medium creating a stable interface where all of the in-place, fluid is again mobile. This regime would, not occur in the absence of gravity. It occurs due to the counter effects of the gravity and viscous forces (Fig. 1c). As the velocity of the displacing fluid increases, the viscous forces dominate, and, the interface breaks into viscous fingers (Fig. 1d). SPEJ p. 293

scholarly journals Carbon dioxide, bicarbonate and carbonate ions in aqueous solutions under deep Earth conditions

2020 ◽  
Vol 22 (19) ◽  
pp. 10717-10725
Author(s):  
Riccardo Dettori ◽  
Davide Donadio
Keyword(s):  
Carbon Dioxide ◽  
Aqueous Solutions ◽  
Upper Mantle ◽  
Crust And Upper Mantle ◽  
Effect Of Pressure ◽  
Deep Crust ◽  
Carbonate Ions ◽  
Deep Earth ◽  
Thermodynamic Conditions

We investigate the effect of pressure, temperature and acidity on the composition of water-rich carbon-bearing fluids under thermodynamic conditions that correspond to the Earth's deep crust and upper mantle.

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