scholarly journals Visualization of Spreading and Non-Spreading Oil Films in Gas- Assisted Gravity Drainage (GAGD) Process Using Novel NOA81 Microfluidic Platform

2021 ◽  
Vol 5 (3) ◽  
pp. 1-10
Author(s):  
Rao DN
Keyword(s):  
Oil Recovery ◽  
High Pressures ◽  
Pore Network ◽  
Reservoir Rock ◽  
Microfluidic Platform ◽  
Reservoir Rocks ◽  
Gas Phases ◽  
Water Alternating Gas ◽  
Physical Resistance ◽  
Oil Films

The presence of oil films in three phase flow of oil, water and gas through reservoir rocks has a significant effect on the recovery efficiency associated with various Enhanced Oil Recovery (EOR) processes like Water Alternating Gas (WAG) and Gas-Assisted Graviry Drainage (GAGD). Visualization of these oil films helps in having a better understanding of the conditions required for the formation of such films in a rock pore network. In this work, we have used a microfluidic platform consisting of Norland Optic Adhesives-81(NOA81) that better mimics the reservoir rock pore geometry, to visualize the oil films in different spreading systems. NOA81 is a transparent polymer with high chemical and physical resistance, which enabled the device to withstand harsh organic solvents as well as high pressures and temperatures encountered in the EOR experiments. This device was designed with pore network similar to that of a consolidated water wet porous rock with varying channel widths and taper, unlike various other platforms using regular square or constant channel width grids. This modification resulted in a more realistic representation of the actual pore network of reservoir rocks. Continuous thinner oil films were observed in the positive spreading system, whereas discontinuous trapped oil blobs were encountered in the negative spreading system. Statistical analysis carried out on the thickness of the oil phase separating water and gas phases indicated significant differences and confirmed the visual observations.

scholarly journals CO2 Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6215
Author(s):  
Manoj Kumar Valluri ◽  
Jimin Zhou ◽  
Srikanta Mishra ◽  
Kishore Mohanty
Keyword(s):  
Oil Recovery ◽  
Power Plants ◽  
Oil And Gas ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Co2 Injection ◽  
Reservoir Properties ◽  
Industrial Facilities ◽  
Water Alternating Gas ◽  
Process Understanding

Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.

A Pore-Network-Modeling Approach To Predict Petrophysical Properties of Diatomaceous Reservoir Rock

2007 ◽  
Vol 10 (06) ◽  
pp. 597-608 ◽  
Author(s):  
Liping Jia ◽  
Cynthia Marie Ross ◽  
Anthony Robert Kovscek
Keyword(s):  
Multiphase Flow ◽  
Capillary Pressure ◽  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Pore Network ◽  
Reservoir Rock ◽  
Pore Network Model ◽  
Rock Types ◽  
Capillary Pressure Curves

Summary A 3D pore-network model of two-phase flow was developed to compute permeability, relative permeability, and capillary pressure curves from pore-type, -size, and -shape information measured by means of high-resolution image analysis of diatomaceous-reservoir-rock samples. The diatomite model is constructed using pore-type proportions obtained from image analysis of epoxy-impregnated polished samples and mercury-injection capillary pressure curves for diatomite cores. Multiple pore types are measured, and each pore type has a unique pore-size and throat-size distribution that is incorporated in the model. Network results present acceptable agreement when compared to experimental measurements of relative permeability. The pore-network model is applicable to both drainage and imbibition within diatomaceous reservoir rock. Correlation of network-model results to well log data is discussed, thereby interpolating limited experimental results across the entire reservoir column. Importantly, our method has potential to predict the petrophysical properties for reservoir rocks with either limited core material or those for which conventional experimental measurements are difficult, unsuitable, or expensive. Introduction Model generation for reservoir simulation requires accurate entering of physical properties such as porosity, permeability, initial water saturation, residual-oil saturation, capillary pressure functions, and relative permeability curves. These functions and parameters are necessary to estimate production rate and ultimate oil recovery, and thereby optimize reservoir development. Accurate measurement and representation of such information is, therefore, essential for reservoir modeling. Relative permeability and capillary pressure curves are the most important constitutive relations to represent multiphase flow. Often, it is difficult to sample experimentally the range of relevant multiphase-flow behavior of a reservoir. In addition to the availability of rock samples, measurements are frequently time consuming to conduct, and conventional techniques are not suitable for all rock types (Schembre and Kovscek 2003). It is impossible, therefore, to measure all the unique relative permeability functions of different reservoir-rock types and variations within a rock type. This lack of constitutive information limits the accuracy of reservoir simulators to predict oil recovery. Simply put, other available data must be queried for their relevance to multiphase flow and must be used to interpret the available relative permeability and capillary pressure information.

The Effects of Surface Roughness on Fluid Displacement Mechanisms and Residual Residual Trapping - A Pore Scale Investigation

2021 ◽  
Author(s):  
Rumbidzai Nhunduru ◽  
Omid Shahrokhi ◽  
Krystian Wlodarczyk ◽  
Amir Jahanbakhsh ◽  
Susana Garcia ◽  
...  
Keyword(s):  
Surface Roughness ◽  
Porous Media ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Micro Structure ◽  
Two Phase ◽  
Fluid Displacement ◽  
Reservoir Rocks ◽  
Residual Trapping ◽  
Network Pattern

<p>Immiscible fluid displacement and the trapping of residual oil and gas phases in the pore spaces of reservoir rocks is critical to geological operations such as carbon geo-sequestration and enhanced oil recovery. In carbon geo-sequestration, residual trapping is advantageous because it ensures long-term storage security of carbon dioxide (CO<sub>2</sub>). In contrast, residual trapping can pose significant challenges during waterflooding in oil recovery operations where large volumes of oil may remain trapped in the interstitial spaces of the porous reservoir rock and cannot be extracted, thereby reducing the efficiency of the recovery process. In such operations, residual trapping is strongly influenced by the inherent surface roughness of the solid rock matrix amongst many factors. Surface roughness occurs in natural reservoir rocks as a result of geological processes that physically, chemically or biologically convert sediments into sedimentary rock (known as diagenesis) and weathering.</p><p>The effects of surface roughness on immiscible two-phase flow are currently not well understood. Previous investigations into residual trapping in porous media have mainly focused on the influence of factors such as pore geometry, wettability, fluids interfacial tension, mobility ratio and injection scenarios. Although some of these studies acknowledge the potential effect of surface roughness, there is still a lack of quantitative characterization and understanding of the influence of surface roughness on immiscible two-phase displacements in porous media.</p><p>In this study, the impacts of surface roughness on immiscible two-phase displacement are quantified. Immiscible two-phase displacement of air by water was conducted in a custom laser-manufactured glass microfluidic chip (micromodel). The glass chip comprised a 2.5D micro-structure analogous to the pore network pattern (micro-structure) of a natural reservoir rock, Oolitic limestone. The pore network pattern consisted of cylindrical pillars 400 µm in diameter arranged in a rhombohedra type of packing, generated on to a glass substrate using an ultrafast, pulsed picosecond laser. Surface roughness is an innate characteristic of laser machined surfaces and as a result, small variations in depth of the porous micro-structure were observed (50 ± 8 µm). The average surface roughness (S<sub>a</sub>) of the laser-machined structure was measured to be 1.2 μm.</p><p>Experimental results for the rough micromodel exhibit high repeatability of fluid displacement patterns (preferential flow pathways) demonstrating that surface roughness has a strong influence on fluid invasion patterns and sweep efficiency and its effects must not be ignored. To ascertain the effects of surface roughness on the fluid displacement process, a direct numerical simulation (DNS) of the fluid displacement process was performed in OpenFoam using the Volume of Fluid (VOF) method assuming zero surface roughness. Comparing the experimental results with the numerical simulations, we show that surface roughness can significantly enhance residual trapping in porous media by up to 49.2%.</p><p> </p>

Adsorption Of Nonionic Surfactants On Clay Minerals

2012 ◽  
Author(s):  
Radzuan Junin ◽  
Tahmineh Amirian ◽  
Ahmad Kamal Idris
Keyword(s):  
Clay Minerals ◽  
Clay Mineral ◽  
Oil Recovery ◽  
Nonionic Surfactants ◽  
Mineralogical Composition ◽  
Reservoir Rock ◽  
Chemical Solution ◽  
Reservoir Rocks ◽  
Oil Water ◽  
Rock Minerals

The adsorption of surfactants from aqueous solutions in porous media is very significant in the enhanced oil recovery (EOR) of oil reservoirs. Surfactant loss due to adsorption on the reservoir rocks weakens the efficiency of the chemical solution injected to decrease the oil–water interfacial tension (IFT). This study investigated the effect of the mineralogical composition of adsorbents on adsorption. Nonionic surfactants were injected into sand packs in which different amounts of clay minerals (kaolinite and illite) were added and compacted in a sand pack holder. The amount of surfactant adsorbed was quantified by subtracting the concentration of surfactants after adsorption from the initial concentration. It was concluded that there is a relationship between the adsorption of nonionic surfactants and the amount of clay mineral in the adsorbents because the quantity of surfactant adsorbed by adsorbents increased when the percentage of clay mineral in the adsorbents increased (from 2 to 8% in the sand packs). The clay mineral illite has a stronger adsorption power for nonionic surfactants than does kaolinite. Key words: Adsorption, reservoir rock minerals, clay minerals, nonionic surfactants

Systematic Surveillance Techniques for a Large Miscible WAG Flood

2011 ◽  
Vol 14 (03) ◽  
pp. 299-309 ◽  
Author(s):  
Manmath Panda ◽  
Derek Nottingham ◽  
David Lenig
Keyword(s):  
Oil Recovery ◽  
Field Data ◽  
Poor Performance ◽  
Field Application ◽  
Reservoir Rock ◽  
Large Field ◽  
Small Scale ◽  
Full Field ◽  
The North ◽  
Water Alternating Gas

Summary Miscible water-alternating-gas (WAG) flooding has proven to be an attractive enhanced-oil-recovery (EOR) method the world over. Successful WAG floods can yield significant additional oil recovery over waterflooding. WAG floods are complex in nature since reduction of residual oil in the pore spaces depends on mass transfer. Optimizing miscibile contact between the injected gas and the reservoir oil over a large rock volume is challenging. This challenge is more manageable in a small-scale pilot flood or a coreflood than in a large field implementation. Numerical-simulation efforts can provide guidance to designing an optimal flood. However, the field application will often reveal challenges that are not discovered in the pilot stage or by the full-field simulation model because the geologic properties and heterogeneity of the reservoir rock are not accurately represented. Integrated surveillance of a WAG flood is the only means to determine whether the flood is working efficiently and the planned additional recovery will be delivered. A well-implemented surveillance plan allows timely intervention to improve the efficiency of an underperforming WAG flood. This paper presents a systematic approach for applying EOR surveillance tools and methods in large miscible WAG floods in the Ivishak reservoirs at the Prudhoe Bay and Eileen West End (EWE) of the North Slope, Alaska. Highlights of these surveillance methods are (1) designed and implemented by a multidisciplinary team, (2) based on proven theory and corroborated with field data, (3) requires easily obtainable and relatively inexpensive field data and analysis, and (4) applied from fault block down to zone levels. Implementation of these tools has helped to identify the efficiency of flood patterns and areas of poor performance, which then can be modified through infill drilling, well recompletion, or WAG-ratio modification to maximize EOR recovery.

scholarly journals High-temperature high-pressure microfluidic system for rapid screening of supercritical CO2 foaming agents

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Ayrat Gizzatov ◽  
Scott Pierobon ◽  
Zuhair AlYousef ◽  
Guoqing Jian ◽  
Xingyu Fan ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Foam Stability ◽  
Pore Network ◽  
Reservoir Rock ◽  
Process Efficiency ◽  
Rapid Screening ◽  
Alpha Olefin Sulfonate ◽  
Foam Formation ◽  
Foaming Agents ◽  
Static Conditions

AbstractCO2 foam helps to increase the viscosity of CO2 flood fluid and thus improve the process efficiency of the anthropogenic greenhouse gas’s subsurface utilization and sequestration. Successful CO2 foam formation mandates the development of high-performance chemicals at close to reservoir conditions, which in turn requires extensive laboratory tests and evaluations. This work demonstrates the utilization of a microfluidic reservoir analogue for rapid evaluation and screening of commercial surfactants (i.e., Cocamidopropyl Hydroxysultaine, Lauramidopropyl Betaine, Tallow Amine Ethoxylate, N,N,N′ Trimethyl-N′-Tallow-1,3-diaminopropane, and Sodium Alpha Olefin Sulfonate) based on their performance to produce supercritical CO2 foam at high salinity, temperature, and pressure conditions. The microfluidic analogue was designed to represent the pore sizes of the geologic reservoir rock and to operate at 100 °C and 13.8 MPa. Values of the pressure drop across the microfluidic analogue during flow of the CO2 foam through its pore network was used to evaluate the strength of the generated foam and utilized only milliliters of liquid. The transparent microfluidic pore network allows in-situ quantitative visualization of CO2 foam to calculate its half-life under static conditions while observing if there is any damage to the pore network due to precipitation and blockage. The microfluidic mobility reduction results agree with those of foam loop rheometer measurements, however, the microfluidic approach provided more accurate foam stability data to differentiate the foaming agent as compared with conventional balk testing. The results obtained here supports the utility of microfluidic systems for rapid screening of chemicals for carbon sequestration or enhanced oil recovery operations.

THE BASIC TYPES OF SECONDARY CHANGES IN RESERVOIR ROCKS IN THE TERRITORY OF THE WEST SIBERIA PLATE

2015 ◽  
pp. 26-30
Author(s):  
A. V. Podnebesnykh ◽  
S. V. Kuznetsov ◽  
V. P. Ovchinnikov
Keyword(s):  
Oil Recovery ◽  
West Siberia ◽  
Recovery Factor ◽  
Change Processes ◽  
The West ◽  
Reservoir Rocks ◽  
Tectonically Active ◽  
Porosity And Permeability ◽  
Active Zones ◽  
Regional Character

On the example of the group of fields in the West Siberia North the basic types of secondary changes in reservoir rocks are reviewed. Some of the most common types of such changes in the West Siberian plate territory include the processes of zeolitization, carbonation and leaching. These processes have, as a rule, a regional character of distribution and are confined to the tectonically active zones of the earth's crust. Due to formation of different mineral paragenesises the secondary processes differently affect the reservoir rocks porosity and permeability: thus, zeolitization and carbonization promote to reducing the porosity and permeability and leaching improvement. All this, ultimately leads to a change of the oil recovery factor and hydrocarbons production levels. Study and taking into account of the reservoir rocks secondary change processes can considerably influence on placement of operating well stock and on planning of geological and technological actions.

Evaluation of Oil Recovery by Water Alternating Gas (WAG) Injection - Oil-Wet & Water-Wet Systems

2011 ◽  
Author(s):  
Abdulrazag Yusef Zekri ◽  
Mohamed Sanousi Nasr ◽  
Abdullah AlShobakyh
Keyword(s):  
Oil Recovery ◽  
Water Alternating Gas ◽  
Wag Injection

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

Nanoparticles Aid Oil Recovery During Alternating Injection

2021 ◽  
Vol 73 (09) ◽  
pp. 62-63
Author(s):  
Chris Carpenter
Keyword(s):  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Surfactant Solution ◽  
Volatile Oil ◽  
Technical Conference ◽  
Reservoir Rock ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Custom Made ◽  
Salinity Water

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201586, “Effect of Silica Nanoparticles on Oil Recovery During Alternating Injection With Low-Salinity Water and Surfactant Into Carbonate Reservoirs,” by Saheed Olawale Olayiwola, SPE, and Morteza Dejam, SPE, University of Wyoming, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Although the potential of nanoparticles (NPs) to improve oil recovery is promising, their effect during alternating injection is still uncertain. The main objective of the authors’ study is to investigate the best recovery mechanisms during alternating injection of NPs, low-salinity water (LSW), and surfactant and transform the results into field-scale technology. The outcome of these experiments revealed that tertiary injection of NPs results in additional oil recovery beyond the limits of LSW. Introduction A series of coreflooding experiments was conducted using several cores with an effective permeability of approximately 1 md to the brine at a temperature and pressure of 70°C and 3,000 psi. The study performs four different alternating injections of NPs with LSW and surfactant to determine optimal oil recovery. The wettability of the rock and fluid and the interfacial tension (IFT) of oil and water are measured to understand the mechanisms of interactions between the fluids and the reservoir rock. Materials A 12×12×12-in. block taken from an outcrop of Indiana limestone reservoir was purchased for this study. Four core plugs with a diameter of 1.5 in., used for the coreflooding experiments, were selected from this block. A synthetic 100,000-ppm (10 wt%) brine was prepared in the laboratory by dissolving sodium chloride (NaCl) and calcium chloride with a ratio of 4:1 in deionized water. The crude oil used in this study was a volatile oil (properties are described in Table 2 of the complete paper) obtained from the Permian Basin in Texas. Injected Fluids. A 10,000-ppm (1 wt%) LSW was prepared by diluting the synthetic brine 10 times. The surfactant solutions were prepared from an anionic sodium dodecyl sulfate (SDS) surfactant. A 1,000-ppm (0.1 wt%) surfactant solution used throughout the experiments was selected on the basis of the estimated critical micelle concentration of 600 to 2,240 ppm for SDS and nanofluid/NaCl. The concentration of silica NPs used in this study was 500 ppm (0.05 wt%). The nanofluids were pre-pared either as a simple solution or as a mixture with other chemicals to make a concentration of 500-ppm silica NPs. Coreflooding System. The established coreflooding system used for this experimental study was custom-made to determine the oil recovery and the relative permeabilities at steady-state and unsteady-state flows. However, the focus of this study is to investigate the effect of silica NPs on oil recovery. The schematic diagram of the coreflooding system is shown in Fig. 1.

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