Fabrication of 2.5D Rock-Based Micromodels With High Resolution Features

2015 ◽  
Author(s):  
Daniel S. Park ◽  
J. Upadhyay ◽  
V. Singh ◽  
Karsten E. Thompson ◽  
Dimitris E. Nikitopoulos
Keyword(s):  
High Resolution ◽  
Fluid Transport ◽  
Reservoir Rock ◽  
Uv Exposure ◽  
Pore Scale ◽  
Total Thickness ◽  
Bath Composition ◽  
Nickel Electroforming ◽  
Thickness Variations ◽  
Minor Pattern

Fabrication of 2.5D rock-based micromodels with high resolution features is presented using SU-8 multi-layer lithography and nickel electroforming for nickel molds. Processes associated with SU-8 were carefully optimized by the use of the vacuum contact, the use of UV filter, and controls of UV exposure doses and baking times. The use of SU-8 MicroSpray enabled the easy fabrication of multi-layers of SU-8, while exhibiting some total thickness variations. The thirteen layered SU-8 samples showed reliable patterning results for features at 10 and 25 μm resolutions, and minor pattern distortions of features at the 5 μm resolution. Flycutting method employed in multi-layer lithography of SU-8 yielded accurate total thickness control within ±1.5 μm and excellent pattern formation for all of 5, 10, and 25 μm features. Electroforming of nickel was optimized with electroplating bath composition and electroplating parameters such as current density to realize the high resolution nickel mold. The fabricated nickel molds from flycutting based SU-8 samples revealed the feasibility of manufacturing the minimum features down to 5 μm for thirteen layers without any pattern distortions. The replication-based micromolding method will allow for fabrication of micromodels in a variety of materials such as polymers and ceramics. The high resolution, 2.5D micromodels will be used for investigation of pore-scale fluid transport, which will aid in understanding the complicated fluidic phenomena occurring in the 3D reservoir rock.

Formation Characterization and Production Forecast of Tight Sandstone Formations in Daqing Oilfield Through Digital Rock Technology

2021 ◽  
Author(s):  
Danhua Leslie Zhang ◽  
Xiaodong Shi ◽  
Chunyan Qi ◽  
Jianfei Zhan ◽  
Xue Han ◽  
...  
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Surfactant Solution ◽  
Fluid Models ◽  
Pore Scale ◽  
Field Development ◽  
Digital Rock ◽  
Small Pore ◽  
Sem Imaging

Abstract With the decline of conventional resources, the tight oil reserves in the Daqing oilfield are becoming increasingly important, but measuring relative permeability and determining production forecasts through laboratory core flow tests for tight formations are both difficult and time consuming. Results of laboratory testing are questionable due to the very small pore volume and low permeability of the reservoir rock, and there are challenges in controlling critical parameters during the special core analysis (SCAL) tests. In this paper, the protocol and workflow of a digital rock study for tight sandstones of the Daqing oilfield are discussed. The workflow includes 1) using a combination of various imaging methods to build rock models that are representative of reservoir rocks, 2) constructing digital fluid models of reservoir fluids and injectants, 3) applying laboratory measured wettability index data to define rock-fluid interaction in digital rock models, 4) performing pore-scale modelling to accelerate reservoir characterization and reduce the uncertainty, and 5) performing digital enhanced oil recovery (EOR) tests to analyze potential benefits of different scenarios. The target formations are tight (0.01 to 5 md range) sandstones that have a combination of large grain sizes juxtaposed against small pore openings which makes it challenging to select an appropriate set of imaging tools. To overcome the wide range of pore and grain scales, the imaging tools selected for the study included high resolution microCT imaging on core plugs and mini-plugs sampled from original plugs, overview scanning electron microscopy (SEM) imaging, mineralogical mapping, and high-resolution SEM imaging on the mini-plugs. High resolution digital rock models were constructed and subsequently upscaled to the plug level to differentiate bedding and other features could be differentiated. Permeability and porosity of digital rock models were benchmarked against laboratory measurements to confirm representativeness. The laboratory measured Amott-Harvey wettability index of restored core plugs was honored and applied to the digital rock models. Digital fluid models were built using the fluid PVT data. A Direct HydroDynamic (DHD) pore-scale flow simulator based on density functional hydrodynamics was used to model multiphase flow in the digital experiments. Capillary pressure, water-oil, surfactant solution-oil, and CO2-oil relative permeability were computed, as well as primary depletion followed with three-cycle CO2 huff-n-puff, and primary depletion followed with three-cycle surfactant solution huff-n-puff processes. Recovery factors were obtained for each method and resulting values were compared to establish most effective field development scenarios. The workflow developed in this paper provides fast and reliable means of obtaining critical data for field development design. Capillary pressure and relative permeability data obtained through digital experiments provide key input parameters for reservoir simulation; production scenario forecasts help evaluate various EOR methods. Digital simulations allow the different scenarios to be run on identical rock samples numerous times, which is not possible in the laboratory.

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 Density Functional Hydrodynamics in Multiscale Pore Systems: Chemical Potential Drive

2020 ◽  
Vol 146 ◽  
pp. 01001
Author(s):  
Oleg Dinariev ◽  
Nikolay Evseev ◽  
Denis Klemin
Keyword(s):  
Density Functional ◽  
Fluid Transport ◽  
Chemical Potential ◽  
Transport Model ◽  
Effective Model ◽  
Pore Scale ◽  
Multiphase Transport ◽  
Novel Approach ◽  
Scale Modelling ◽  
Significant Generalization

We use the method of density functional hydrodynamics (DFH) to model compositional multiphase flows in natural cores at the pore-scale. In previous publications the authors demonstrated that DFH covers many diverse pore-scale phenomena, starting from those inherent in RCA and SCAL measurements, and extending to much more complex EOR processes. We perform the pore-scale modelling of multiphase flow scenarios by means of the direct hydrodynamic (DHD) simulator, which is a numerical implementation of the DFH. In the present work, we consider the problem of numerical modelling of fluid transport in pore systems with voids and channels when the range of pore sizes exceed several orders of magnitude. Such situations are well known for carbonate reservoirs, where narrow pore channels of micrometer range can coexist and interconnect with vugs of millimeter or centimeter range. In such multiscale systems one cannot use the standard DFH approach for pore-scale modeling, primarily because the needed increase in scanning resolution that is required to resolve small pores adequately, leads to a field of view reduction that compromises the representation of large pores. In order to address this challenge, we suggest a novel approach, in which transport in small-size pores is described by an upscaled effective model, while the transport in large pores is still described by the DFH. The upscaled effective model is derived from the exact DFH equations using asymptotic expansion in respect to small-size characterization parameter. This effective model retains the properties of DFH like chemical and multiphase transport, thus making it applicable to the same range of phenomena as DFH itself. The model is based on the concept that the transport is driven by gradients of chemical potentials of the components present in the mixture. This is a significant generalization of the Darcy transport model since the proposed new model incorporates diffusion transport in addition to the usual pressure-driven transport. In the present work we provide several multiphase transport numerical examples including: a) upscaling to chemical potential drive (CPD) model, b) combined modeling of large pores by DFH and small pores by CPD.

scholarly journals Development of a numerical workflow based on <i>μ</i>-CT imaging for the determination of capillary pressure–saturation-specific interfacial area relationship in 2-phase flow pore-scale porous-media systems: a case study on Heletz sandstone

Solid Earth ◽  
2016 ◽  
Vol 7 (3) ◽  
pp. 727-739 ◽  
Author(s):  
Aaron Peche ◽  
Matthias Halisch ◽  
Alexandru Bogdan Tatomir ◽  
Martin Sauter
Keyword(s):  
High Resolution ◽  
Pore Size ◽  
Capillary Pressure ◽  
Interfacial Area ◽  
Scale Model ◽  
Phase Flow ◽  
Pore Scale ◽  
Pore Size Distributions ◽  
Phase Saturation

Abstract. In this case study, we present the implementation of a finite element method (FEM)-based numerical pore-scale model that is able to track and quantify the propagating fluid–fluid interfacial area on highly complex micro-computed tomography (μ-CT)-obtained geometries. Special focus is drawn to the relationship between reservoir-specific capillary pressure (pc), wetting phase saturation (Sw) and interfacial area (awn). The basis of this approach is high-resolution μ-CT images representing the geometrical characteristics of a georeservoir sample. The successfully validated 2-phase flow model is based on the Navier–Stokes equations, including the surface tension force, in order to consider capillary effects for the computation of flow and the phase-field method for the emulation of a sharp fluid–fluid interface. In combination with specialized software packages, a complex high-resolution modelling domain can be obtained. A numerical workflow based on representative elementary volume (REV)-scale pore-size distributions is introduced. This workflow aims at the successive modification of model and model set-up for simulating, such as a type of 2-phase problem on asymmetric μ-CT-based model domains. The geometrical complexity is gradually increased, starting from idealized pore geometries until complex μ-CT-based pore network domains, whereas all domains represent geostatistics of the REV-scale core sample pore-size distribution. Finally, the model can be applied to a complex μ-CT-based model domain and the pc–Sw–awn relationship can be computed.

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