Low Displacement Efficiency Research Articles

Activated single nucleotide mismatch determination through toehold-embedded hairpin-mediated strand displacement reaction alongside CRISPR-Cas12a for detection of TP53 point mutation

The CRISPR-Cas12a-based diagnostic platform is renowned for its high sensitivity and, when coupled with the toehold-mediated strand displacement (TMSD) reaction, enables the detection of single nucleotide mismatch (SNM). However, conventional TMSD with the CRISPR-Cas12a system suffers from signal leakage due to overlapping activator sequences and low displacement efficiency. Here, we propose a toehold-embedded hairpin-mediated strand displacement (THMSD) method and leverage the magnesium attenuation effect of CRISPR-Cas12a for selective single-point mutation detection in the TP53 gene. This approach effectively mitigates signal leakage as the hairpin DNA retains partial crRNA targeting sequences within its loop, preventing sequence overlap with the trigger and direct Cas12a activation. Additionally, the magnesium attenuation effect reduces background signal and enhances selectivity. We investigated toehold length and mismatch position to detect SNM with a high discrimination factor (DF). This high DF allows the THMSD/CRISPR-Cas12a system to differentiate between TP53 R273H mutant and TP53 wildtype genes for cancer screening at low abundances, down to 0.1 % with a concentration of 20 pM. When used for screening between H1975 and WI38 cells, the statistically significant difference was attainable with polymerase chain reaction (PCR) template loading as low as 4 ng. These results pave the way for developing CRISPR-Cas12a-based methods to effectively detect TP53 mutations as lung cancer biomarkers.

Comparative Evaluation of the Application Effectiveness of Intelligent Production Optimization Methods in Offshore Oil Reservoirs

The development of offshore oil fields confronts challenges associated with high water cut and low displacement efficiency. Reservoir injection-production optimization stands out as an effective means to reduce costs and enhance efficiency in offshore oilfield development. The process of optimizing injection and production in offshore oil reservoirs involves designing strategies for a large number of wells and optimization time steps, constituting a large-scale, complex, and costly optimization computation problem. In recent years, with the rapid advancements in big data and artificial intelligence technologies, sophisticated evolutionary computation methods have found widespread application in reservoir injection-production optimization problems. However, the abundance of intelligent optimization algorithms raises the question of how to choose a method suitable for the complex optimization background of offshore oilfield injection-production optimization. This paper provides a detailed overview of the application of an existing differential evolution algorithm (DE), conventional surrogate-assisted evolutionary algorithm (CSAEA), and global–local surrogate-assisted differential evolution (GLSADE) in the context of practical offshore oilfield injection-production optimization problems. A comprehensive comparison of their performance differences is presented. The study concludes that the global–local surrogate-assisted evolutionary algorithm is the most suitable method for addressing the current challenges in offshore oilfield injection-production optimization.

Three-dimensional modeling of nanoconfined multiphase flow in clay nanopores using FIB-SEM images of shale

<p>Understanding the flow characteristics within shale nanopores is crucial for enhancing hydrocarbon recovery. However, the flow characteristics of wetting and non-wetting fluids on nanopore surfaces differ significantly, limiting the accurate prediction of hydrocarbon accumulation and migration. This work introduces the Euler-Euler volume of fluid method to establish a multiphase flow numerical model in shale nanopores, considering complex pore topology, slip flow, and capillary effects. Based on natural three-dimensional shale nanoporous systems constructed from FIB-SEM images, single-phase water/oil flow and water-oil forced imbibition simulations are carried out under the complete wetting condition. Results show that the displacement pressure is reduced and the imbibition rate is elevated considering nanoscale slip effects. As imbibition progresses, the pressure and imbibition rate gradually converge toward the values observed in conventional flows. In complete wetting nanoporous systems, water flow experiences high pressure and low velocity, whereas the pressure for oil flow is significantly reduced. Forced imbibition may undergo a transition from capillary force-dominated to viscous force-dominated, with a negative displacement pressure at the initial stage. Furthermore, the fluctuations in water-oil mass flow considering the slip effect are less pronounced than those observed in conventional flows, leading to reduced residual fluid saturation in blind-end pores and pore bodies caused by snap-off events. Pore systems with poor connectivity and narrow throat structures correspond to low displacement efficiency. The findings of this work explain the impact of nanoscale slip effects on flow characteristics in unconventional reservoirs, contributing to the reasonable assessment of fluid flow capacity and facilitating production planning.</p>

How to Regulate the Migration Ability of Emulsions in Micro-Scale Pores: Droplet Size or Membrane Strength?

Micro visualization has become an important means of solving colloid and interface scientific problems in enhanced oil recovery. It can establish a relationship between a series of performance evaluations of an oil-water interface under macroscopic dimensions and the actual application effect in confined space, and more truly and reliably reflect the starting and migration behavior of crude oil or emulsion in rock pores. In this article, zwitterionic surfactant alkyl sulfobetaine (ASB) and anionic extended surfactant alkyl polyoxypropylene sulfate (A145) were employed as flooding surfactants. The macroscopic properties of the surfactant solutions, such as the oil-water interfacial tension (IFT), the interfacial dilational rheology and the viscosity of crude oil emulsions, have been measured. At the same time, we link these parameters with the oil displacement effect in several visual glass models and confirm the main factors affecting the migration ability of emulsions in micro-scale pores. The experimental results show that ASB reduces the IFT through mixed adsorption with crude oil fractions. The flat arrangement of the large hydrophilic group of ASB molecules enhances the interactions between the surfactant molecules on the oil-water interface. Compared with sulfate, betaine has higher interfacial membrane strength and emulsion viscosity. A145 has a strong ability to reduce the IFT against crude oil because of the larger size effect of the PO chains at the oil side of the interface. However, the membrane strength of A145 is moderate and the emulsion does not show a viscosity-increasing effect. During the displacement process, the deformation ability of the front emulsions or oil banks is the main controlling factor of the displacement efficiency, which is determined by the membrane strength and emulsion viscosity. The strong interfacial membrane strength and the high emulsion viscosity are not conducive to the migration of droplets in pore throats and may result in low displacement efficiency.

Characteristics and mechanisms of supercritical CO2 flooding under different factors in low-permeability reservoirs

In recent years, supercritical CO2 flooding has become an effective method for developing low-permeability reservoirs. In supercritical CO2 flooding different factors influence the mechanism of its displacement process for oil recovery. Asynchronous injection–production modes can use supercritical CO2 to enhance oil recovery but may also worsen the injection capacity. Cores with high permeability have higher oil recovery rates and better injection capacity, however, gas channeling occurs. Supercritical CO2 flooding has a higher oil recovery at high pressure levels, which delays the occurrence of gas channeling. Conversely, gas injection has lower displacement efficiency but better injection capacity at the high water cut stage. This study analyzes the displacement characteristics of supercritical CO2 flooding with a series of experiments under different injection and production parameters. Experimental results show that the gas breakthrough stage has the fastest oil production and the supercritical CO2 injection capacity variation tendency is closely related to the gas–oil ratio. Further experiments show that higher injection rates represent significant ultimate oil recovery and injection index, providing a good reference for developing low-permeability reservoirs.

Design simulation and test of hydraulic control system of RFID reamer while drilling

With the gradual improvement of exploration and development in deep and ultra-deep Wells, the demand for slim-hole drilling is increasing day by day. However, both the phenomenon of neck constriction and drill-jamming accident occur from time to time in the drilling process, and the annulus clearance between borehole and casing is too small, which resulting in high slurry annulus pressure loss, low displacement efficiency and poor cementing quality. Therefore, a kind of RFID reamer while drilling has come into being, the reamer blades can be controlled to open and close with the aid of RFID tag recognition technology without increasing the drilling cost, so as to complete the reaming operation while drilling. Taking the hydraulic control system as the research object, the hydraulic circuit has been designed based on AMESim software in this paper, so has its dynamic performance simulation analysis been carried out, finally, the ground test has been completed, the results show that the hydraulic control system is capable of accurately identifying the RFID tag information to drive the reamer blades to open and close, the overall pressure loss of the tool is about 1.0 MPa as the blades opened completely, which meets the requirements of field test.

Computational fluid dynamics for ameliorating oil recovery using silicon-based nanofluids and ethanol in oil-wet reservoirs

Impulsive emulsion formation, porous media wettability alteration, and interfacial tension (IFT) reduction are a list of advantages gained from the application of nanoparticles for enhanced oil recovery (EOR). However, low displacement efficiency (DE) coupled with in-effective mixing of the injected nanofluid to redeem the immobile volume of crude oil subsurface present a major challenge to the petroleum industry. The molecular chemistry of ethyl alcohol (ethanol) solvent enables the genesis of strong covalent bonds/mixing with the dense oil. As a result, the fastening converts the aromatic state of the crude oil to a lighter component to ease the flow. In this paper, we numerically investigated the potential for improving dead oil recovery in a heterogeneous rock setting using a blend of ethanol and silicon-based nanofluids to describe the EOR fluid. Herein, silica, silane and silicon carbide nanofluids were studied for their DE with ethanol as the co-solvent. A 2D heterogeneous pore-model was created and discretized to define the computational domain. Computational fluid dynamics code (ANSYS Fluent) facilitated the induction and analysis of interfacial property dynamics within the modelling space. The simulation was performed using the improved delayed detached-eddy simulation method, whereas the continuum surface-force equation with the Euler–Euler mixture multiphase method was used to model the fluid–wall and fluid–fluid adhesions at interfaces. Findings revealed that, silica nanofluid performed optimally compared to its counterpart. Furthermore, approximately 55.34% of the immobile oil was recovered using the optimal blend formulation comprising of equal proportion of silica nanofluid and ethanol. The increase in disjoining pressure and water molecules concentration at the fluid–wall​ contact, and the reduction in interfacial tension due to the evolution of in-situ surface acting agents (surfactants) from the chemical reaction kenetics accounts for this increase. In addition, the blend demonstrated good thermal stability for typical reservoir temperatures of around 400 K due to high intrinsic thermal resilence of silica nanoparticles present in the mixture.

Study on Water Displacing Gas Relative Permeability Curves in Fractured Tight Sandstone Reservoirs Under High Pressure and High Temperature.

Water–gas relative permeability is an important parameter for the rational development of gas fields. Conventional measurement methods are carried out at normal temperature and pressure without considering the actual conditions of high temperature and high pressure. The water displacing gas process in fractured tight sandstone reservoirs, under formation condition (116 MPa and 160 °C), was simulated by the self-manufactured displacing apparatus. The results show that cores under formation condition have the larger residual gas saturation, the smaller two-phase coexisting area, the lower water/gas relative permeability, and the lower displacement efficiency than that under normal conditions. The relative permeability declines slowly and the residual gas saturation is high, making the process of replacing the gas more difficult. The number and the interconnection quality of fractures affect the shape and the position of the displacing curves. It provides a reference for the rational development and further research of fractured tight sandstone reservoir.

Feasibility study of improved unconventional reservoir performance with carbonated water and surfactant

For unconventional reservoirs, water flooding performs poorly because of low displacement efficiency; gas flooding shows limited enhanced oil recovery (EOR) capability due to gas breakthrough. Carbonated water injection (CWI) and active CWI (ACWI) are promising EOR methods which combine advantages of water and gas flooding. This paper provides experimental and numerical studies of carbonated water and surfactant injection based on a case study in Changqing Oilfield, China, which is the first time to investigate the feasibility of CWI and ACWI for tight oil reservoirs. This study compares performances of active water injection (AWI), CWI, Water altering gas (WAG), and ACWI. Experimental results reveal that the oil recovery of CWI is 2.7% more than WAG. ACWI achieves the highest incremental oil recovery (9.43%) among four methods. The sensitivity analyses of ACWI + WAG is further implemented experimentally, which demonstrates that ACW as a pre-flood improves 7% of oil recovery during WAG process. For Changqing tight reservoir cores, the optimal injection volume of ACW is 0.8 pore volume. Numerical simulations are conducted to validate the capability of cubic Equation-of-State coupled with Henry's law (EOS/H model) for CWI in tight oil reservoirs, indicating EOS/H model is applicable to correlate phase behavior of carbonated water and oil system. This paper, for the first time, investigates the EOR performance of ACWI in tight oil reservoirs. These results explore the feasible application of using CWI/ACWI in tight oil reservoir development.

Unstable Displacement of Non-aqueous Phase Liquids with Surfactant and Polymer

In this paper, we study two-phase multicomponent displacement of two immiscible fluids in both homogeneous and heterogeneous porous media. In many applications such as enhanced oil recovery, fluid mixing and spreading can be detrimental to the efficacy of the process. Here, we show that when an initially immobile phase is being displaced by a finite-size slug of solvents (surfactant and polymer), viscous fingering significantly enhances mixing and spreading of solvents. These effects are similar to those caused by medium heterogeneity and lead to poor displacement efficiency. We first quantify the displacement efficiency subject to different mobility ratios, Peclet numbers, and levels of medium heterogeneity. We observe a non-monotonic behavior in displacement efficiency as a function of mobility ratio, indicating that although stable frontal interface is desirable, miscible viscous fingering on the rear interface will eventually disintegrate the solvents slugs and reduce the displacement efficiency. Then, we show that miscible viscous fingering developing on the rear interface of the chemical slug could be greatly suppressed when viscosity contrast is gradually decreased using exponential or linear functions, leading to 10% increase in displacement efficiency while using the same amount of chemicals. To elucidate this low displacement efficiency, we study the evolution of mixing, spreading, and interfacial length and show that while higher viscosity ratios are quite effective in mobilizing the initially immobile phase in 1D displacements, they are in fact detrimental in 2D unstable displacements since they enhance mixing and spreading of solvents.

Numerical simulation of cementing displacement interface stability of extended reach wells

The well cementing is important during the extended reach well drilling and the completion, whereas the displacement efficiency and the interface stability are important to guarantee the success of the cementing. In this paper, the interface stability of the cement slurry is simulated using the computational fluid dynamics software. The calculation results indicate that during the displacement, the length of the displacement interface increases with the increase of the deviation angle. The larger the eccentricity, the more significant the velocity difference, along with a longer displacement interface length, a less stable interface, and a lower displacement efficiency. Therefore, to guarantee the cementing quality and maintain a high displacement efficiency, the eccentricity should be controlled within 0.5. Application of a casing centralizer will dramatically improve the interface stability, decrease the dilution zone length of the interface and thus, is beneficial to the slurry cementing and displacement. The simulations are verified with an average absolute deviation less than 3.76% and the 45° helix angle of the rigid centralizer is recommended. Combining the data of an extended reach well on-site, methods are proposed for improving the displacement efficiency and the interface stability during the well cementing and displacement with complex boreholes. These numerical methods can be used to provide some theoretical guidance for designing the cementing of an extended reach well.

Very High Temperature Laboratory CO2 Injection

Carbon dioxide (CO2) injection is the most promising technique to enhance the recovery of high gravity oil with the existing oil price situation. Even though, challenges still exist for thick and heterogeneous reservoirs at very high temperature. The problems faced in such reservoirs are low displacement efficiency and very high injection pressure requirement for a miscible displacement. The effort being done by researchers to overcome the situations is the use of silica nanoparticle as an agent to form CO2-silica nanoparticle foam. Currently, the related literature shows that CO2 miscible displacement is rarely performed at very high temperature and consequently no relevant effort has been made to investigate the stability of CO2-silica nanoparticle foam, while there are many oil reservoirs with temperature of higher than 250 oF. Therefore, related studies on such situations are needed. The present work consists of two stages. First, slimtube and coreflood experiments of CO2 injection are conducted at about 270 oF, respectively, to both determine the Minimum Miscibility Pressure (MMP) of the selected live oil system and the oil recovery. Secondly, CO2-silica nanoparticle foam stability in various brine salinity at such high temperature will be investigated and effectiveness of the selected stable foam will be tested through an oil displacement using native cores.In this paper, the results of both slimtube and coreflood experiments are first presented. A live paraffinic oil with 34 oAPI is used. The standard slimtube apparatus is employed. Stacked core composing of three native core plugs of different permeability ranging from 75 to 503 milidarcies are used to represent rock heterogeneity. At a temperature of 270 oF, MMP of the oil obtained from the slimtube experiment is 2960 psi, about 100 psi higher than that obtained from the coreflood experiment. The slimtube test gives oil recovery 94.2% and the coreflood as expected yields lower recovery, 84% of the initial oil in place. The importance of the tests is two folds that the MMP of the oil system is firmly known while the existing empirical correlations estimate the values ranging from 2718 to 5578 psi and a relatively low coreflood oil recovery suggests further investigation of stability of CO2-silica nanoparticle foam at that temperature in an attempt for enhancing the oil recovery.

Study on gas-liquid relative permeability experiments of fractured-porous reservoirs

Abstract For carbonate reservoirs, gas-water and oil-gas relative permeability curve are of importance for parameters calculation in oil-field development, dynamic analysis and numerical reservoir simulation. The oil-gas/gas-water relative permeability curves were measured with unstable method under normal temperature and low pressure, using fifteen artificial fractured cores. The shape and change characteristics of gas/water and oil/gas relative permeability curve were mainly analyzed. The results showed that for the relative permeability curve of water driving gas. The saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency has a good power-function relation with core permeability. In addition, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will decrease with the increasing of core permeability. However, for oil-gas relative permeability curves, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will increase with the increasing of core permeability. It should be noted that the gas relative permeability presents a straight line in the normalized relative permeability curve, which indicates that the main flow is dominated by fracture with low displacement efficiency. The research results provide theory basis for fracture-vuggy carbonate reservoir development and new research idea for the further study of this kind of reservoir.

Experimental study on timing and pattern of gas injection in low permeability reservoir

Experiments were conducted to study the selection of development methods for low permeability reservoir exploitation after water drive, including the effects of different gas injection cycle times and different injection modes on oil displacement efficiency. Results showed that both gas injection cycle time and injection mode have significant effects on oil displacement efficiency. Based on the results of gas injection cycle time of the displacement with mode shifting to gas drive when water cut reaches 50% and 100%, it can be concluded that in the low permeability reservoir, which is exploited by water drive in the early time, the sooner the gas injection, the higher the oil displacement efficiency is. Because high water saturation can cause serious water-blocking effect, leading to a large amount of trapped oil and low displacement efficiency. Further, in view of the results of water drive, gas injection, and water alternating gas (WAG) flooding, it is obvious that WAG flooding is one of the best methods in enhanced oil recovery. Under the effect of gravity differentiation, WAG flooding can spread to the upper reservoir, which cannot be swept by water drive. Thus, the oil recovery factor can be improved effectively. However, it should be noted that gas injectivity should be considered in the field test.

Improved Sweep Efficiency By Selective Plugging of Highly Watered Out Zones By Alcohol Induced Precipitation

Abstract A new selective plugging process has been developed for improving volumetric sweep efficiency and thus, the enhancement of recovery from oil reservoirs. The new process is based on the theory of "salting out" in which a non-electrolyte is added to water to reduce the solubility of electrolytic substances. In this new process, following a concentrated brine preflush, one or more slugs of a water soluble alcohol (such as ethanol) are injected into a reservoir. The mixing of alcohol with brine will cause salt precipitation. Alcohol and concentrated brine prefer to flow through water flooded zones because of the high relative permeability to these fluids. The formation of solid precipitate can partially or completely block the high-permeability zones and divert subsequent fluid flow into lower permeability zones where oil saturations are greater. A larger volume of the reservoir is thus contacted by the injected fluid, improving the overall volumetric sweep efficiency and the oil recovery. In homogeneous sandpack flow tests, a permeability reduction of up to 70% is obtained. In heterogeneous sandpack flow tests, the permeability is reduced to 50% of original brine permeability. The experimental results show that the new selective plugging process can recover an additional 15% of original oil in place (OOIP). There are advantages to this new method over other selective permeability reduction techniques. The process can be applied to deep and shallow oil reservoirs. In addition, the plugging of more permeable zones is easy to remove by injecting brine with low salt concentration, if required. Introduction A large portion (as much as 65% average) of the original oil in place in oil reservoirs is not recoverable with conventional waterflooding technology(1). This low oil recovery is due to both low displacement efficiency and low volumetric sweep efficiency. The oil industry has been seeking enhanced oil recovery methods to improve displacement efficiency and volumetric sweep efficiency. In oil reservoirs, almost all formations are heterogeneous. Some regions have low permeability while others have high permeability. All injected fluids have the tendency to flow through the least resistant regions (having the highest permeability) bypassing the lower permeability zones. In a waterflooded reservoir, after a substantial amount of oil is recovered from high permeability areas, the recovery process may become uneconomical because the water-oil ratio is high. Therefore, if a selective permeability plugging method could be developed to block off highly water-invaded regions any subsequently injected fluids would have to pass through regions not previously invaded by water. As a result selective permeability plugging would improve volumetric sweep efficiency and increase ultimate oil recovery. Interest in plugging highly water-invaded zones in oil reservoirs for improved sweep efficiency, has increased over the past several decades. Numerous methods have been studied to plug highly water-invaded regions including foams, polymers, surfactants, and microbes(2–8). However, each of these methods has limited application because of some inherent problems. For example, polymers are degraded by shear forces as they are propagated through reservoir rock. In surfactant processes, adsorption of surfactants on minerals is a major cause of surfactant degradation and uneconomic performance.

Calculation of Water Displacement by Gas in Development of Aquifer Storage

Abstract During the initial growth of a gas bubble in an aquifer storage reservoir the injected gas tends to override the water. The resulting low displacement efficiency and big rate of gas travel down-structure make it difficult to maintain water-free production. This paper illustrates the use of two-dimensional, two-phase calculations to simulate this gas-water displacement. Calculations were performed for a stratified aquifer and for several homogeneous sands differing in permeability, porosity and thickness. Results are discussed and compared with performance predictions obtained from the simpler Buckley-Leverett and Dietz formulas. This comparison indicates the necessity for the two-dimensional calculations in realistically simulating the gravity override of the water by injected gas. Introduction In recent years natural gas has been stored near markets in aquifers where insufficient storage capacity is available in depleted fields. Operators of these aquifer storage reservoirs have encountered technical problems relating to the gas-water displacement accompanying initial growth of these gas bubble. Injected gas tends to override the water, with a resultant low displacement efficiency and high rate of gas travel down-structure toward spill points. Low displacement efficiency makes if difficult to sustain water-free gas production. Sometimes the fingering of gas down-structure may be so pronounced that the injection rate must be severely curtailed, which excessively lengthens the time required for bubble growth. This paper is concerned with estimating - for given aquifer characteristics and fluid properties the displacement efficiency, rate of gas movement down-structure and rate of gravity drainage of water behind the gas front. Several published articles relate to simulative capability necessary to handle this problem. The Dietz formulae and Buckley-Leverett method have some applicability to the problem. Woods and Comer reported one - dimensional, radial calculations which accounted for the two-phase flow of gas and water. Most recent research directed toward understanding aquifer behavior in relation to gas storage has concentrated on single-phase flow in aquifer. Douglas, Peaceman and Rachfords presented a method for calculating multidimensional two-phase flow in reservoirs; their method has been applied in work reported by Nielsen and Tek, Blair and Peaceman and Goddin. Refs. 5 and 7 show comparisons between experimental data and calculations similar to those employed here. One purpose of this paper is to illustrate the use of two-dimensional, two-phase flow calculations in simulating the difficult problem of water displacement by gas in a vertical cross-section. The pronounced fluid density and viscosity, differences combine with the disparity in horizontal and vertical dimensions of the cross-section to pose one of the more difficult problems in reservoir simulation. The calculations described account for capillary and gravity forces, relative permeability and reservoir heterogeneity. An example reservoir is described and calculated results are presented for a variety of injection rates and values of permeability, reservoir thickness and dip angle. A second purpose is to compare the two-dimensional calculations with results obtained from the Buckley-Leverett and Dietz formulas. For this reason most calculations were performed for a simplified example reservoir to which the latter techniques night reasonably be applied However, the computer program employed applies equally well to cases involving arbitrary spatial variations of permeability porosity, reservoir thickness and dip angle. SPEJ P. 105ˆ

Certain Wettability Effects In Laboratory Waterfloods

Certain Wettability Effects In Laboratory Waterfloods