Brine Injection Research Articles

Scope of Implementation of Low Salinity Nanofluid to Improve Oil Recovery in a Part of the Hapjan Oil Field of Upper Assam Basin

The application of nanoparticles in the field of Enhanced Oil Recovery (EOR) has been an emerging technology in recent years. Earlier studies have shown that the nanofluids containing nanoparticles (NPs) of average size (<100 nm) can enhance the oil recovery through wettability alteration of rock, reduction of mobility ratio, reduction of oil-aqueous solution interfacial tension (IFT), reduction of sand production and improvement of sweep efficiency. Low Salinity Waterflooding (LSW) has been utilized as a promising EOR method in the last two decades. Recent studies have found that nanoparticle-assisted LSW embraces both nanoparticles and ions as EOR agents in the injection brine. This study investigates the scope of implementation of the low salinity nanofluid EOR using silica nanoparticles to improve oil recovery in the Tipam Reservoir Sandstone of the Hapjan Oil Field of Upper Assam Basin, India. The analysis of the reservoir brine, reservoir rock and crude oil shows the presence of divalent cations (Ca2+ and Mg2+), clay minerals (Illite and Smectite) and polar compounds (Asphaltene and Resin) respectively. The presence of the divalent cations, clay minerals and polar compounds in the Crude Oil/Brine/Rock system of a sandstone reservoir is the prerequisite for implementing low salinity nanofluid EOR. The study shows that the low salinity nanofluids can shift the wettability of the rock to a more water-wet state. It is also observed that the silica nanoparticles can increase the nanofluid viscosity and reduce the oil-nanofluid IFT, which can improve the recovery of oil. The experimental results show that the study area has great potential for the low salinity silica nanofluid EOR to improve oil recovery.

Quantifying the effects of pressure management for the Williston basin Brine Extraction and Storage Test (BEST) site using machine learning

Active reservoir management (ARM) through brine extraction can reduce pressure buildup during large-scale implementation of carbon capture and storage (CCS) projects. This study used machine learning (ML)-assisted approaches to analyze bottomhole pressure (BHP) responses to various brine injection and extraction scenarios. Field monitoring data were collected over a 2-year operation period at two injection wells and one extraction well (about 400 m away) as part of a Brine Extraction and Storage Test (BEST) in the North Dakota portion of the Williston Basin. Injection activities increased the BHPs at the injection wells by around 0.70 MPa (∼100 psi) during the operation period. Extraction activities demonstrated the capability to decrease the BHPs at the injection wells by approximately 0.21–0.34 MPa (30–50 psi) depending on the ratio of the extraction and injection well flow rates (the “extraction ratio” – a normalization procedure used in the analysis). The pressure reduction provided by the extraction well equated to 30–50 % of the pressure buildup at the injection well. This work shows how ML analytics can play a key role in estimating reservoir pressure responses for complex injection and extraction activities during pressure management practices of CCS projects.

Active‐Source Seismic Imaging of Fault Re‐Activation and Leakage: An Injection Experiment at the Mt Terri Rock Laboratory, Switzerland

AbstractWe conducted a time‐lapse seismic experiment utilizing automated active seismic source and sensor arrays to monitor a reactivated fault within the Opalinus clay formation at the Mont Terri Rock Laboratory (Switzerland), an analog caprock for geologic carbon storage. A series of six brine injections were conducted into the so‐called Main Fault to reactivate it. Seismic instrumentation in five monitoring boreholes on either side of the fault was used to continuously probe changes in P‐wave travel‐times associated with fault displacement and leakage. We performed time‐lapse travel‐time tomography on five hundred sequential data sets; this revealed a zone of decreased P‐wave velocity, up to 16 m/s, during each injection cycle, followed by a velocity increase during shut‐in. These results demonstrate varying elastic property perturbations, both spatially and temporally, along the fault plane during reactivation. We then interpreted these velocity changes in terms of fault dilation induced by pressurized fluids along the fault.

Multi-well combined solution mining for salt cavern energy storages and its displacement optimization

Improving the water solution mining rate of the salt rock layer while reducing energy consumption is the core idea for promoting the construction of salt cavern energy storage. In this work, a novel multi-well combined solution mining method for salt cavern energy storages was presented, and a displacement optimization model incorporating sub-models for outlet brine concentration, solution mining rate, and energy consumption of water injection was proposed to maximize the solution mining efficiency. The accuracy of the proposed model is verified by comparing the simulated results with the field data. The results show that under basically the same solution mining rate, the energy consumption of brine injection can decrease by 18.82 %. If 0.49 % of the solution mining rate of the salt cavern can be sacrificed, energy consumption can be reduced by 7.40 %. A special focus was given to the well selection schemes, which indicated that optimization of well selection schemes could reduce energy consumption by 3.61 %. This work could add further insights into the inter-coupling relationship between outlet brine concentration, solution mining rate, and energy consumption of water injection, and help to reduce the energy consumption of water injection and improve solution mining rate.

Pore-scale study of the effects of DTPA chelating agent flooding on oil recovery utilizing a clay-coated micromodel

The use of diethylenetriaminepentaacetic acid (DTPA) chelating agent has shown promising results for enhanced oil recovery (EOR) in prior research. Several mechanisms, mainly resulting from rock-fluid interaction, have been proposed for chelating agent flooding; however, little attention has been paid to fluid-fluid interaction thus far. The assessment of these mechanisms has primarily relied on macroscopic techniques such as core flooding. This paper aims to investigate the injection of DTPA brine and its dominant mechanisms at the pore scale using a clay-coated micromodel. The micromodel tests were performed under oil-wet and water-wet states. For a more precise examination of fluid/fluid interactions, the dynamic interfacial tension (IFT) and Zeta potential were measured. It was observed that the injection of DTPA brine in water-wet state changed the saturation distribution and increased oil recovery. Based on visual inspections, this change in saturation distribution could potentially be linked to the formation of micro-dispersions and viscoelastic interfacial phenomena. Micro-dispersions facilitate flow to unswept areas, and viscoelastic interface formation reshapes the interface between oil and brine, causing disconnected oil droplets to coalesce and thus increase recovery. Under the oil-wet state, the micro-dispersion formation and wettability alteration can be the dominant mechanisms, and the amount of recovered oil was higher than that observed in the water-wet state. Furthermore, Zeta potential measurements at the interface between brine and oil showed a more negative value for DTPA brine, which is effective in wettability alteration and micro-dispersions stability. The results indicate that IFT reduction was not significant enough to be considered the dominant mechanism, although it assists in DTPA brine penetration into the crude oil and subsequent micro-dispersion formation.

Pore-Scale Analysis of the Permeability Damage and Recovery during Cyclic Freshwater and Brine Injection in Porous Media Containing Non-Swelling Clays

Permeability damage in subsurface porous media caused by clay mobilization is encountered in many engineering applications, such as geothermal energy, water disposal, oil recovery, and underground CO2 storage. During the freshwater injection into rocks containing brine, the sudden decrease in salinity causes native clay fines to detach and clog pore throats, leading to a significant decline in permeability. The clay fines detach due to weakened net-attractive forces binding them to each other and the grain. Past experiments link this permeability damage on the immediate history of the salinity and the direction of flow. To better understand this phenomenon, we conducted pore-scale simulations of cyclic injection of freshwater and brine into sandstone containing Kaolinite clay. Our simulations establish a link between the clay-fine trajectory and the permeability trend observed by Khilar and Fogler (1983). For a uniform clay size of 3 microns, we observe a permeability decline by two orders of magnitude during freshwater injection with respect to brine injection. Increasing salinity and simultaneously reversing flow direction restores the permeability. The permeability restoration upon reversing the brine flow direction is attributed to the unblocking of pore throats in the reverse direction by the movement of the clay particles along the grain surfaces by the hydrodynamic force and the strong net-attractive force under high salinity.

The Effect of Multiple Cycles of Surfactant-Alternating-Gas Process on Foam Transient Flow and Propagation in a Homogeneous Sandstone

Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm3/min, Nca = 3×10-7). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm3/min to 0.06 cm3/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm3/min.

Experimental investigation and prediction of saturation exponent in carbonate rocks: the significance of rock-fluid properties

Hydrocarbon reserves are commonly estimated from electrical logs based on the Archie’s law. Therefore, understanding the concepts and precise determination of Archie’s parameters play an essential role in reservoir studies. The electrical properties of carbonates are affected by both microstructures and wetting characteristics of these heterogeneous rocks. Understanding of these effects and prediction of Archie’s parameters are significant theoretical and experimental challenges. In this paper, these effects were analyzed separately using rocks with various lithologies including limestone, dolomitic limestone and dolostones. Samples with different sedimentary textures (grainstones and packstones), porosities and pore types were also considered under different laboratory conditions. For microstructure effects analysis, 16 heterogeneous carbonate samples having a wide range of microstructures were selected. To decrease wetting effect, the washed samples were tested in air–brine injection system at ambient conditions to measure saturation exponent. Subsequently, in order to investigate the influence of the wetting characteristics on this exponent, 25 homogeneous limestone samples were employed for water–oil injection under reservoir conditions. The porous plate was used as a standard technique to determine the saturation exponent as an electrical index. The results showed that pore connectivity and wettability are the main factors affecting the saturation exponent. Heterogeneity, including the presence of large pores and bimodal texture, is another effective factor that complicates the relationship between saturation exponent and wettability. Furthermore, results indicate variation of the saturation exponent with fluid saturation. Finally, equations were obtained to interpret and calculate the saturation exponent using capillary pressure data by mercury injection method. The derived equations clearly demonstrate the significant impact of the studied parameters on the saturation exponent in carbonate rocks.

Microfluidics for Carbonate Rock Improved Oil Recovery: Some Lessons from Fabrication, Operation, and Image Analysis

Summary After the successful implementation of lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional coreflooding experiments. Potentially, microfluidics can offer a fast, efficient, low-footprint, and low-cost method to screen many variables such as injection brine composition, reservoir temperature, and aging history for their effect on crude oil (CRO) release, calcite dissolution, and CO2 storage at the pore scale. Generally, visualization of the fluid displacements is possible, offering valuable mechanistic information. Besides the well-known glass- and silicon-based chips, microfluidic devices mimicking carbonate rock reservoirs are currently being developed as well. In this paper, we discuss different fabrication approaches for carbonate micromodels and their associated applications. One approach in which a glass micromodel is partially functionalized with calcite nanoparticles is discussed in more detail. Both the published works from several research groups and new experimental data from the authors are used to highlight the current capabilities, limitations, and possible extensions of microfluidics for studying carbonate rock systems. The presented insights and reflections should be very helpful in guiding the future designs of microfluidics and subsequent research studies.

The impact of CO2 saturated brine temperature on wormhole generation and rock geomechanical and petrophysical properties

One solution to attain net zero CO2 emissions is the sequestration of CO2 in subterranean formations. Deep limestone saline aquifers provide excellent storage sites for CO2 due to their high solubility in water and vast aquifer volumes. This study investigates the potential changes in rock petrophysical and geomechanical properties caused by the reaction of carbonated brine (CO2+brine) and limestone rock, as well as the effect of temperature on wormhole generation. Three samples of Indiana limestone (100% calcite) with dimensions of 1.5 inches in diameter and 3 inches in length, 15% average porosity, and 2 mD average permeability were used. The samples were flooded at 1 mL/min and 2000 psi with a carbonated brine consisting of total dissolved salts of 120,000 ppm. To evaluate the effect of temperature on limestone-carbonated brine reaction at CO2 underground storage conditions, the experiments were conducted at three different temperatures (35, 60, and 85 °C). The samples' Young's modulus and Poisson's ratio at different confining pressures were measured before and after carbonated brine coreflooding. Additionally, we used a medical Computed Tomography (CT) scanner to visualize the created wormholes and quantify their volumes. We observed the generation of a wormhole in each of the experiments after 19.7, 26.7, and 46.9 pore volumes (PVs) of CO2-saturated brine were injected at 35 °C, 60 °C, and 85 °C, respectively. Moreover, the lowest temperature treatment created a straight wormhole with less void volume compared to the other temperatures. Wormhole generation at 85 °C showed the largest reduction in rock strength in terms of Young Moduli (YMs) than the other experiments despite showing the lowest reactivity. To the best of our knowledge, this is the first study to reveal the impact of temperature on wormhole generation due to the injection of CO2-saturated brine in limestone. This study also demonstrates that wormhole generation increases CO2 storage capacity; however, CO2 relative permeability increases, implying that CO2 will flow faster and accumulate primarily underneath the caprock. Furthermore, before injecting CO2, the well integrity in hotter carbonate reservoirs should be thoroughly examined. Conversely, this study reveals that CO2 or carbonated water could be utilized for acid stimulation.

Effect of wettability and phase distribution on critical salt concentration for fines migration initiation in sandstone reservoirs

Fines migration in sandstone oil reservoirs during different field operations is influenced by the salinity of injected brine. When salinity drops below a critical salt concentration (CSC), fines migration is initiated, leading to pore throat blockage and formation damage. Factors such as rock wettability, fluid type, fines size and concentration, and flow rate contribute to the severity of this issue. However, the impact of phase distribution and rock wettability on the CSC remains unexplored. Most results are reported for water-wet systems, but in many cases, assuming a strong water-wet state is not accurate. The current research fills that gap and provides new insights by investigating the relationship between the CSC, phase distribution, and rock wettability.Upper Berea sandstone cores were used in this study, and the CSC was experimentally determined. Brine was injected into strong water-wet and weak water-wet core samples. The injection brine salinity was gradually reduced to identify the salinity at which fines migration initiated within the core. The analysis of pressure drops and effluent analysis was applied to estimate CSC at different wettability states.The step-by-step reduction in salinity led to CSCs of 0.12 M and 0.09 M NaCl for the weak water-wet core and strong water-wet core in the presence of oil, respectively. A weak water-wet system results in a higher CSC value compared to a strong water-wet system because fine particles are contained within a thin water film, and weak water wettability facilitates their easy migration under low reduced salinity conditions. The CSC corresponded to the point of maximum pressure difference and the highest concentrations of produced fines. The findings of this research provide valuable insights into the significant influence of rock wettability and phase distribution on the initiation of fines migration. These parameters must be carefully determined and considered during the design phase of production and enhanced oil recovery in sandstone reservoirs to ensure efficient operations.

The impact of grain size heterogeneity on the performance of low-salinity waterflooding in carbonate formations

Low-salinity waterflooding (LSWF) is a proven enhanced oil recovery method for many target fields. The efficiency of this technique depends on both operational factors as well as reservoir settings such as heterogeneity. Micro-scale rock heterogeneity can critically affect the performance of LSWF as it governs the flow path of the injected water, oil-brine-rock contacts and trapping mechanisms, thus sweep efficiency. However, there exist lack of experimental data and detailed understanding of the effect of grain size heterogeneity on LSWF performance. To address this gap, a systematic series of coreflooding experiments were designed using artificial calcite core plugs to investigate the effect of micro-scale heterogeneity, such as grain size and grain heterogeneity, on oil recovery factor by high-salinity waterflooding (HSWF) and LSWF. High salinity formation water, seawater, and diluted seawater were used as injection brines. For this purpose, two relevant grain size ranges (a) from 38 to 75 µm and (b) from 75 to 125 µm were considered to fabricate homogeneous plugs. Heterogeneous core plugs were made by mixing (a) and (b) grain samples. The artificial cores were initialized with the formation brine and crude oil, and aged to restore wettability. Then a set of coreflooding experiments were performed using the mentioned brine samples, in both secondary and tertiary modes by considering a shut-in period.The results reveal that grains size (or micro-scale) heterogeneity has a significant negative impact on both HSWF and LSWF performance and reduces the oil recovery efficiency of HSWF by approximately 15%. This is primarily attributed to the bypassing and entrapment of oil in heterogeneous cores. Moreover, the results show that regardless of the grain size, LSWF in homogeneous plugs result in almost similar recovery factors. The key finding of this study is that LSWF in heterogeneous plugs is more effective and recovers almost 10% more oil compared to HSWF. This is attributed to wettability alteration as indicated by the reduction of water relative permeability endpoint and delay of breakthrough time. The improvement in oil recovery was consistent with the results obtained from the flotation tests and dynamic IFT measurements. However, although LSWF outperforms HSWF in heterogeneous cores, the ultimate recovery factor becomes less in these plugs. Besides, superior performance of secondary flooding was observed compared to tertiary mode for LSWF, especially in cores with heterogeneous grain sizes, leading to almost 10% higher recovery factor.The novel insights gained through this research help identify the proper targets for LSWF in terms of small-scale heterogeneity and can be potentially applied in other water-based EOR techniques.

Advanced Digital-SCAL Measurements of Gas Trapped in Sandstone

Trapped gas saturation (Sgr) plays an important role in subsurface engineering, such as carbon capture and storage, H2 storage efficiency as well as the production of natural gas. Unfortunately, Sgr is notoriously difficult to measure in the laboratory or field. The conventional method of measurement—low-rate unsteady-state coreflooding—is often impacted by gas dissolution effects, resulting in large uncertainties of the measured Sgr. Moreover, it is not understood why this effect occurs, even for brines carefully pre-equilibrated with gas. To address this question, we used high-resolution X-ray computed tomography (micro-CT) imaging techniques to directly visualize the pore-scale processes during gas trapping. Consistent with previous studies, we find that for pre-equilibrated brine, the remaining gas saturation continually decreased with more (pre-equilibrated) brine injected and even after the brine injection was stopped, resulting in very low Sgr values (possibly even zero) at the pore-scale level. Furthermore, we were able to clearly observe the initial trapping of gas by the snap-off effect, followed by a further shrinkage of the gas clusters that had no connected pathway to the outside. Our experimental insights suggest that the effect is related to the effective phase behavior of gas inside the porous medium, which due to the geometric confinement, could be different from the phase behavior of bulk fluids. The underlying mechanism is likely linked to ripening dynamics, which involves a coupling between phase equilibrium and dissolution/partitioning of components, diffusive transport, and capillarity in the geometric confinement of the pore space.

Fracture Surface Evolution During Acidized Brine Injection in Calcareous Mudrocks.

During hydraulic fracturing, the oxic hydraulic fracturing fluid physically and chemically alters the fracture surface and creates a "reaction-altered zone". Recent work has shown that most of the physicochemical changes occur on the shale fracture surface, and the depth of reaction penetration is small over the course of shut-in time. In this work, we investigate the physicochemical evolution of a calcite-rich fracture surface during acidized brine injection in the presence of applied compressive stress. A calcite-rich Wolfcamp shale sample is selected, and a smooth fracture is generated. An acidized equilibrated brine is then injected for 16 h, and the pressure change is measured. A series of experimental measurements are done before and after the flood to note the change in physicochemical properties of the fracture. High resolution computed tomography scanning is conducted to observe the fracture aperture growth, which shows an increase of ∼8.3 μm during the course of injection. The fracture topography, observed using a surface roughness analyzer, is shown to be smoother after the injection. The calcite dissolution signature, i.e., surface stripping of calcite, is observed by X-ray fluorescence, and mass spectrometry of the timer-series of the effluent also points in the same direction. We conclude that mineral dissolution is the primary mechanism through which the fracture aperture is growing. The weakening of the fracture surface, along with the applied compressive stresses, promotes erosion of the surface generating fines which reduce the fracture conductivity during the course of injection. In this work, we also highlight the importance of rock mineralogy on the fracture evolution mechanism and determine the thickness of the "reaction altered" zone.

Two-phase displacement dynamics in fractured porous media of varying wettability states: A micromodel experimental investigation of matrix/fracture interactions

Matrix-fracture interactions are significant in determining multiphase flow behavior in fractured porous media. We investigated the impact of these interactions on dynamic displacement events and flood-front patterns in a fractured micromodel, with two matrix regions having different permeabilities, of varying wettability states. The effects of injection rate and viscosity were studied during the injection of blank brine and polymer solutions, respectively, under oil-wet (hydrophobic) and water-wet (hydrophilic) conditions. The influence of reducing interfacial tension was examined by injecting a surfactant solution into the oil-wet micromodel. Under oil-wet conditions, brine invaded the high-permeability matrix producing a stepwise increase in water saturation during the low and intermediate rate experiments. The high rate induced fluid displacements within both matrices, but trapped more oil in the high-permeability zone due to what we labeled as the high-rate interruption effect. The stepwise invasion was also observed in the two matrices during the polymer solution injection, contrary to the smoother invasion of the surfactant solution. In the water-wet model, the high-permeability matrix exhibited final fluid saturations resembling those in the oil-wet model after brine injection. However, unlike in the oil-wet model, brine invaded the low-permeability matrix. The polymer solution suppressed trapping and improved the sweep efficiency across the two matrix regions. Our results provide new insights into the pore-scale evolution of fluid saturation during two-phase flow in fractured porous systems under varying wettability conditions.

Pore-scale study of calcite dissolution during CO2-saturated brine injection for sequestration in carbonate aquifers

The calcite reaction with carbonate acid is a prerequisite to release cations providing the reactant for mineral trapping, however, the complicated multiple physicochemical processes during calcite dissolution are hardly precisely captured in carbonate aquifers, impeding the CO2 sequestration technology. In this work, a pore-scale numerical study based on the lattice Boltzmann method coupled fluid flow, mass transport, heterogeneous reactions, and calcite structure evolution is implemented to investigate the calcite dissolution process. Firstly, the impact of pressure difference on this reaction is analyzed to identify two characteristic dissolution patterns. Selecting two typical pressure differences, namely 0.036 and 0.36 Pa, the dissolution dynamics under different temperatures from 25 to 85 °C is then investigated by species concentration and solid distributions elucidating that the effect of pressure difference on calcite dissolution will drop with the increment of temperature. Moreover, the regime diagram of calcite dissolution is plotted based on the relation between temperature and pressure. Finally, to upscale the simulation results to the representative element volume scale, the temporal evolution of normalized permeability, the normalized permeability-porosity relationship and the optimal operations are explored to find that the maximum discrepancy of the normalized permeability with the time among all cases is approximately seven times and the best operating conditions promoting the mineral trapping are a high-temperature formation with a high injection rate.

Deep learning for multiphase segmentation of X-ray images of gas diffusion layers

High-resolution X-ray computed tomography (micro-CT) has been widely used to characterise fluid flow in porous media for different applications, including in gas diffusion layers (GDLs) in fuel cells. In this study, we examine the performance of 2D and 3D U-Net deep learning models for multiphase segmentation of unfiltered X-ray tomograms of GDLs with different percentages of hydrophobic polytetrafluoroethylene (PTFE). The data is obtained by micro-CT imaging of GDLs after brine injection. We train deep learning models on base-case data prepared by the 3D Weka segmentation method and test them on the unfiltered unseen datasets. Our assessments highlight the effectiveness of the 2D and 3D U-Net models with test IoU values of 0.901 and 0.916 and f1-scores of 0.947 and 0.954, respectively. Most importantly, the U-Net models outperform conventional 3D trainable Weka and watershed segmentation based on various visual examinations. Lastly, flow simulation studies reveal segmentation errors associated with trainable Weka and watershed segmentation lead to significant errors in the calculated porous media properties, such as absolute permeability. Our findings show 43, 14, 14, and 3.9% deviations in computed permeabilities for GDLs coated by 5, 20, 40, and 60 w% of PTFE, respectively, compared to images segmented by the 3D Weka segmentation method.

Effect of pH and Surfactant Concentration Sodium Lignosulfonate (SLS) towards Reduction of Silica Mass from Geothermal Brine

Geothermal energy source is one of the wealth of mineral resources that are being widely used. Geothermal Power Plant is a solution to the needs of New Renewable Energy to overcome energy needs and dependence on renewable energy. However, there were important problems that occurred in the geothermal field, namely the formation of silica scaling in the production pipe causing the brine injection process to be disrupted, the injection process aims to maintain the volume of the geothermal reservoir and maintain the quantity of production steam in the long run. Therefore, controlling silica in the brine injection path in geothermal fields is very much needed. This paper discussed the decrease in silica mass influenced by pH and the addition of Sodium Lignosulfonate (SLS) surfactants that studying the changes in pH (7, 8 and 9), and surfactant concentrations (0.05, 0.15 and 0.30% (w/v)). The results showed that the dissolved silica in the geothermal solution was reduced and could be controlled by the addition of SLS surfactants. The greater the surfactant concentration and pH, the more the mass of silica will be taken. The best conditions are at pH 9 and SLS surfactant concentration 0.30%w/v.

Effect of a narrow channel inserted in the conventional ice block mold with brine injection on the productivity and ice formation behavior of the low temperature brine bathing ice production process

ABSTRACT Block ice is cuboid in shape. It is produced by filling water into a mold and bathing it in a brine pool. For 270 × 560 × 1500 mm3 the production batch time is 24 hours. The aim of this work is to improve the conventional mold so that it has a batch time shorter than the low electrical cost duration of 11 hours. A narrow channel having nearly the same width as the mold was installed inside the mold. The brine is injected from the middle of the channel's open end at the mold base by a ½ inch nozzle. A CFD model was developed and validated with the experimental data. It was found that the optimum pool temperature and injection flow rate may be approximated to be −10 and 80 lpm, respectively. Heat transfer can be assumed to be in one dimension in the mold depth direction. As long as the channel height is less than that of the mold, the batch time will be comparable to that of the conventional mold. Regardless of the pool temperature, for a certain channel height, the channel can contribute to the productivity at approximately the same rate. The batch time was 9.73 hours.

Experimental Study on CH4 Hydrate Dissociation by the Injection of Hot Water, Brine, and Ionic Liquids

Thermal stimulation is an important method to promote gas production and to avoid secondary hydrate formation during hydrate exploitation, but low thermal efficiency hinders its application. In this work, hydrate dissociation was carried out in synthesized hydrate-bearing sediments with 30% hydrate saturation at 6.9 MPa and 9 °C. Ionic liquids, such as 1-butyl-3-methylimidazolium chloride (BMIM-Cl) and tetramethylammonium chloride (TMACl), were injected as heat carriers, and the promotion effects were compared with the injection of hot water and brine. The results showed that the injection of brine and ionic liquids can produce higher thermal efficiencies compared to hot water. Thermodynamic hydrate inhibitors, such as NaCl, BMIM-Cl, and TMACl, were found to impair the stability of CH4 hydrate, which was conducive to hydrate dissociation. By increasing the NaCl concentration from 3.5 to 20 wt%, the thermal efficiency increased from 37.6 to 44.0%, but the thermal efficiencies experienced a fall as the concentration of either BMIM-Cl or TMACl grew from 10 to 20 wt%. In addition, increasing the injection temperature from 30 to 50 °C was found to bring a sharp decrease in thermal efficiency, which was unfavorable for the economics of gas production. Suitable running conditions for ionic liquids injection should control the concentration of ionic liquids under 10 wt% and the injection temperature should be around 10 °C, which is conducive to exerting the weakening effect of ionic liquids on hydrate stability.