Cumulative Recovery Research Articles

An Improved Parallel Heterogeneous Long Short-Term Memory Model with Bayesian Optimization for Time Series Prediction

Currently, Deep Learning (DL) with the Recurrent Neural Networks (RNN) variants is being applied successfully in many domains of Engineering for prediction. In view of the demand for precise forecasting and the aid of Artificial Intelligence Tools, time series prediction reveals a vital task in decision-making and risk assessment. However, the application of novel Recurrent DL models for obtaining an accurate prediction of time series is yet to be explored. Recent trends reveal that Hybrid Neural Networks and DL models are appropriate for time series forecasts. At the same time, the model's selection and the hyperparameter's tuning can greatly impact its performance. To address this problem, a parallel long-term memory (PLSTM) model integrated with Bayesian hyperparameter optimization (PLSTM-BO) is proposed for time series prediction. The model is tuned in terms of key parameters, including the number of neurons, dropout, learning rate, and optimization technique. The model's performance is assessed using the SARS-COVID-19 cumulative cases, deaths, recovery cases, and NIFTY 50 stock closing price time series dataset. The obtained results convey that the current model exhibits remarkable performance compared to existing models.

Evaluation of Viscosity Reducers for Heavy Oil Reservoirs: Experimental Testing and Numerical Simulation.

The application of thermal recovery methods in Chad's heavy oil fields has proven to be challenging, necessitating the development of chemical cold production technologies. The mechanisms causing heavy oil viscosity remain unclear, and the effects of adding viscosity reducers in wells with varying water contents are not well understood. In this study, the composition and structure of Chad's heavy oil samples were experimentally analyzed, revealing that the viscosity is primarily due to the accumulation of isoprenoid-like components and the high concentration of side-chain naphthenes in the oil's saturated fraction. Based on this mechanism, viscosity reducers were screened, with DG, a high-molecular-weight water-soluble viscosity reducer, demonstrating the most effective results. Numerical simulation was then employed to characterize the mechanism of viscosity reducers and to model the impact of adjusting daily production rates and introducing viscosity reducers in wells with different water contents on the cumulative oil recovery. The field numerical model was used to simulate for 10 years, and the results showed that for high water content wells, the injection of viscosity reducer reduced the daily fluid volume by 10%, and the cumulative recovery rate increased by 6.75%; for low water content wells, the injection of viscosity reducer increased the daily fluid volume by 20%, and the cumulative recovery rate increased by 3.08%. This research aims to provide new insights into the development of heavy oil reservoirs.

Experimental investigation of hybrid enhanced oil recovery techniques for Ugnu Heavy Oil on Alaska North Slope

The Alaska North Slope (ANS) is endowed with a substantial reservoir of heavy oil, estimated at 12–18 billion barrels, primarily concentrated within the Ugnu reservoirs. These deposits, situated at depths ranging from 2,000 to 4,000 feet, lie in close proximity to the permafrost and have undergone biodegradation, resulting in in-situ viscosities reaching thousands of centipoise. Following the success in recovering the somewhat less heavy, viscous oils through polymer injection, the deposits in Ugnu Formation are garnering significant interest. Although thermal recovery methods are commonplace for heavy oils, applying these methods on ANS is impractical, given the adjacency to continuous permafrost. Therefore, non-thermal hybrid enhanced oil recovery (cEOR) methods, such as solvent (e.g., CO2) and low salinity water (LSW) based, or LSW and polymer-based techniques, emerge as the primarily feasible options for recovering these vast heavy oil resources. This study experimentally investigates, via systematically carried out fluid property and phase behavior tests and a series of sand-pack coreflood experiments, the potential to enhance the recovery of Ugnu heavy oils. The coreflood experiments reveal the synergistic effect of combining liquid-CO2 with LSW to be the most promising approach in this study as a water alternating gas (WAG) process results in the cumulative recovery factor of 83.5%, doubling the recovery obtained by continuous low salinity waterflood. Additionally, the liquid-CO2-LSW WAG process demonstrated an additional benefit for CO2 storage, with about 25% of the pore volume of the liquid-CO2 injected being sequestered at the end of the injection process. This significant recovery improvement is attributed to a substantial reduction of oil viscosity upon contact with the liquid CO2 during the soaking period, with a reduction of up to 95% of the original oil viscosity. Meanwhile, in-situ emulsion generation was observed in the oil produced from the continuous LSW flooding. This was also evident by the increased differential pressure across the sand-pack compared to that of the liquid-CO2 alternating LSW process. The promising results of this study indicate significant potential for liquid-CO2 alternating LSW injection as an effective cEOR technique for Ugnu heavy oils.

Simulation-Based Optimization Workflow of CO2-EOR for Hydraulic Fractured Wells in Wolfcamp A Formation

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO2 huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

High-turbulence fine particle flotation cell optimization and verification

Microfine mineral particles have a small size, light weight, and low inertia, making it difficult for them to deviate from streamlines and collide with bubbles. Conventional flotation operations consume a large amount of reagents and exhibit poor flotation indicators. This study employs computational fluid dynamics (CFD) simulation and hydrodynamic testing to investigate the flow field within a high-turbulence microfine particle flotation machine equipped with a multilayer impeller–stator configuration, and validates the practical application performance of the microfine particle flotation machine through single-batch flotation experiments. Result shows that the impeller region of the traditional mechanical stirring flotation machine has a turbulent energy dissipation rate of 20 m²/s³, whereas that for the microfine particle flotation machine averages over 120 m²/s³. In the flotation verification, the cumulative recovery rate of the fine particle flotation machine is increased by 28% compared with that of the traditional KYF flotation machine. The flotation rate is also 1.3 times that of the KYF, demonstrating stronger selectivity for fine particle concentrates. It has certain guiding significance for the resource utilization of fine particle minerals.

Non-thermal recovery of a viscous oil with a surfactant-polymer process

The goal of this work is to improve recovery of a viscous oil reservoir at 70 °C using a non-thermal process. Polymer floods can improve sweep efficiency, but leave behind a residual oil saturation. A surfactant-polymer flood has the potential to improve both the sweep as well as the displacement efficiency. Phase behavior experiments with the viscous oil, water and surfactants were conducted to identify surfactants. 1D and 2D sandpack displacements were conducted to evaluate the efficacy of the process. Phase behavior experiments showed Winsor type I behavior with a low interfacial tension using a single surfactant, but not ultralow tension. Water flood recovered about 50% OOIP and reduced the oil saturation to about 45% in 1D floods. The subsequent SP flood increased the cumulative oil recovery to 99% in sandpacks when the viscosity of chemical slugs exceeded the oil viscosity. When the permeability decreased (as in a Bentheimer core), the oil recovery decreased to about 86%. Secondary SP floods also recovered most of the oil and faster than tertiary floods. Reduction of polymer concentration (and viscosity to about 1/4th of the oil viscosity) reduced the oil recovery, especially in 2D sandpack floods. Decrease in interfacial tension increased the requirement of polymer concentration to maintain flood front stability. This flood demonstrates the effectiveness of Winsor type I SP formulation for viscous oil, high permeability reservoirs. Such a SP process would reduce the carbon footprint of viscous oil recovery compared to that of thermal processes.

Research and Application of Chemical Sand Control without Blockage in WellBore

Abstract The main sand control methods for oil production wells in a certain Oilfield include mechanical filling sand control, artificial well bore reconstruction with coated sand, and phenolic resin sand control. Mechanical filling for sand control requires the well bore to be intact, with residual pipe columns in the well that cannot meet the testing fluid profile, and subsequent processing often requires major repairs; The construction pressure of artificial well bore is high, and the production of chemical resin sand control is significantly reduced. In order to ensure the consolidation strength, both sand control processes are under displacement operations, and the well bore above the top boundary of the perforated layer is fixed with a plug that needs to be drilled. Research on a new type of chemical sand control technology for well bore without blockage. By using biomass cellulose crystals with smaller particle size and resin in the sand fixing agent combination, the sand particles in the formation are well coated, and condensation reaction occurs to achieve the goal of sand control. The casing will not solidify to create well bore blockage, avoiding later drilling and plugging operations. The construction pressure is low, the damage to the casing is small, and it has a certain degree of selectivity. After sand control, the water content can be reduced by more than 10%. It is suitable for sand control operations in casing damage wells, casing change wells, high inclination wells, and horizontal wells, and can be used for packer construction. As of December 2023, there have been 8 on-site applications with a success rate of 100%, Average water content reduced by 13%, and a cumulative recovery of 2936 tons of oil production. This has safely and efficiently solved the sand control problem in complex well conditions.

Self-assembly behavior of BS12 in water for combination flooding potential: Deep eutectic solvent as a component

Deep eutectic solvent (DES) as standalone or mixed with surfactant flooding has been increasingly recognized and has attracted attention in enhanced oil recovery (EOR). However, the association between self-assembly behavior and the EOR potential of zwitterionic surfactants in DES-water systems has not been profoundly studied. In this work, two choline-based DES were prepared preferentially. The self-assembly and micellar growth of dodecyl dimethyl betaine (BS12) in DES-water systems was investigated by particle size analysis, fluorescence spectroscopy, and transmission electron microscopy. In the system containing 60 wt% DES, micelles were stretched ∼100 times via complexation, hydrogen bond, and electrostatic shield. Afterward, the key parameters of EOR were evaluated. The synergy effect of DES and BS12 in water reduced the critical micelle concentration (cmc) and the oil–water interfacial tension (IFT) to below 1 mmol/L and 0.1 mN/m, respectively. DES strengthened the BS12 aqueous solution to transform the oil-wet sandstone into water-wet. Therefore, the forces on the crude oil in the pore throats may favor its removal. In the mixed system, larger micelles exhibited better crude oil solubilization performance. Compared with the surfactant-alone system, the solubilization and low IFT brought by DESs/BS12 systems increased the cumulative crude oil recovery rate to 10.74 % and 7.61 %, thus showing promising potential for EOR.

Operational strategies and well design for reservoir thermal energy storage (RTES)

The intermittency of renewable energy sources necessitates effective energy storage solutions. This study narrows in on reservoir thermal energy storage (RTES) as a system to bridge the supply–demand gap through the storage and recovery of heated water for periods ranging from daily to monthly timescales. By injecting hot water into subsurface formations and later retrieving it for use in electricity generation or direct heating, the viability of RTES is explored for load-levelling applications, typically on daily to monthly timescales rather than extended seasonal or multi-year storage. Many factors including formation parameters (e.g. permeability, porosity, thermal conductivity of rock, thickness and insulating layers), completion parameters such as injection well design, operational parameters such as injection and production rates, and schedule affect the facility's performance. The two key performance indicators (KPI) considered herein are the produced water temperature and the heat recovery factor. In this study, three operational strategies and four different well completions were investigated using a coupled fluid–thermal simulation model. Heat loss from the upper and lower boundaries of the reservoir was also studied. While the immediate impact of initial hydro-thermal charging on produced water temperature may not persist in the long-term operation, it does influence the overall system efficiency by reducing the cumulative heat recovery. Through detailed analysis, it is demonstrated that vertical injection across the entire well length offers a balanced approach between minimizing pumping costs and maximizing heat extraction efficiency. This study establishes basic calculations for developing innovative operational and completion strategies to maximize the long-term economic benefit of RTES.

Development of surfactant formulation for high-temperature off-shore carbonate reservoirs.

The residual oil left behind after water flooding in petroleum reservoirs can be mobilized by surfactant formulations that yield ultralow interfacial tension (IFT) with oil. However, finding ultralow IFT surfactant formulations is difficult for high-temperature, off-shore, carbonate reservoirs. These reservoirs are often water-flooded with seawater (with a lot of divalent ions), which is often incompatible with many surfactants at high temperatures. The goal of this research is to develop a surfactant formulation for an off-shore carbonate reservoir at 100°C previously flooded by seawater. Surfactant-oil-brine phase behavior was studied for formulations, starting from a single surfactant to mixtures of surfactants and a co-solvent. Mixtures of three surfactants and one co-solvent were needed to produce ultralow IFT formulations for the oil of interest. The surfactant system with polymer mobility control was tested in crushed reservoir rock packs. The cumulative oil recovery was >99% for the surfactant-polymer (SP) flood with an optimal salinity gradient. The constant salinity SP floods with seawater increased oil recovery significantly beyond the water flood (cumulative oil recovery >91%), even though the recovery was lower than that of the optimal salinity gradient SP flood. Our experimental work demonstrates the effectiveness of the surfactant formulation for a high-temperature carbonate reservoir at seawater salinity.

Pharmacokinetics, mass balance, tissue distribution, metabolism, and excretion of [14C]aficamten following single oral dose administration to rats

The pharmacokinetics, metabolism, excretion, mass balance, and tissue distribution of [14C]aficamten were evaluated following oral administration of an 8 mg/kg dose in Sprague Dawley rats and in a quantitative whole-body autoradiography study in Long Evans rats. [14C]Aficamten accounted for ∼80% and a hydroxylated metabolite (M1) accounted for ∼12% of total radioactivity in plasma over 48-h (AUC0–48). Plasma t max was 4-h and the t 1/2 of total plasma radioactivity was 5.8-h. Tissues showing highest Cmax exposures were myocardium and semitendinosus muscle. Most [14C]aficamten-derived radioactivity was excreted within 48-h post-administration. Mean cumulative recovery in urine and faeces over 168-h was 8.3% and 90.7%, respectively. In urine and bile, unchanged aficamten was detected at <0.1 and <0.2% of dose, respectively; however, based on total radioactivity excreted in urine (8.0%) and bile (51.7%), approximately 60% of dose was absorbed. [14C]Aficamten was metabolised by hydroxylation with subsequent glucuronidation where the most abundant metabolite recovered in bile was M5 (35.2%), the oxygen-linked glucuronide of hydroxylated aficamten (M1a). The major metabolite detected in faeces was a 1,2,4-oxadiazole moiety ring-cleaved metabolite (M18, 35.3%), shown to be formed from the metabolism of M5 in incubations with rat intestinal contents solution.

“Component flow” conditions and its effects on enhancing production of continental medium-to-high maturity shale oil

Based on the production curves, changes in hydrocarbon composition and quantities over time, and production systems from key trial production wells in lacustrine shale oil areas in China, fine fraction cutting experiments and molecular dynamics numerical simulations were conducted to investigate the effects of changes in shale oil composition on macroscopic fluidity. The concept of “component flow” for shale oil was proposed, and the formation mechanism and conditions of component flow were discussed. The research reveals findings in four aspects. First, a miscible state of light, medium and heavy hydrocarbons form within micropores/nanopores of underground shale according to similarity and intermiscibility principles, which make components with poor fluidity suspended as molecular aggregates in light and medium hydrocarbon solvents, such as heavy hydrocarbons, thereby decreasing shale oil viscosity and enhancing fluidity and outflows. Second, small-molecule aromatic hydrocarbons act as carriers for component flow, and the higher the content of gaseous and light hydrocarbons, the more conducive it is to inhibit the formation of larger aggregates of heavy components such as resin and asphalt, thus increasing their plastic deformation ability and bringing about better component flow efficiency. Third, higher formation temperatures reduce the viscosity of heavy hydrocarbon components, such as wax, thereby improving their fluidity. Fourth, preservation conditions, formation energy, and production system play important roles in controlling the content of light hydrocarbon components, outflow rate, and forming stable “component flow”, which are crucial factors for the optimal compatibility and maximum flow rate of multi-component hydrocarbons in shale oil. The component flow of underground shale oil is significant for improving single-well production and the cumulative ultimate recovery of shale oil.

한중 양국 중소기업해외채권 회수제도 비교 연구

According to the Korea Trade Insurance Corporation, the amount of funds that have not yet received payment for exports in 2021 is 82 million US dollars (106.6 billion Korean won), and the total amount of accounts receivable in the past five years has reached 1.3 trillion Korean won. According to the Korea Trade Association, although the issuance scale of foreign bonds is increasing, the cumulative recovery rate is as low as around 30%. The average recovery rate of overseas accounts receivable owed by Chinese export enterprises is only 20%. Combined with a 5% export bad debt rate, it basically means that 4% of the annual export amount cannot be recovered. For small and medium-sized enterprises with weak risk resistance, cash flow is crucial for their survival. In general, there are two common ways to obtain compensation for uncollected debts: by purchasing pre export credit insurance or by seeking an ECA agency for agency recovery. The public export credit agencies (ECA) K-SURE and SINOSURE of the two countries are exploring the differences and similarities in overseas bond recovery systems, while hoping to provide better bond recovery methods for small and medium-sized enterprises and help with overseas bond recovery.

Pore-scale probing CO2 huff-n-puff in extracting shale oil from different types of pores using online T1–T2 nuclear magnetic resonance spectroscopy

CO2 huff-n-puff shows great potential to promote shale oil recovery after primary depletion. However, the extracting process of shale oil residing in different types of pores induced by the injected CO2 remains unclear. Moreover, how to saturate shale core samples with oil is still an experimental challenge, and needs a recommended procedure. These issues significantly impede probing CO2 huff-n-puff in extracting shale oil as a means of enhanced oil recovery (EOR) processes. In this paper, the oil saturation process of shale core samples and their CO2 extraction response with respect to pore types were investigated using online T1–T2 nuclear magnetic resonance (NMR) spectroscopy. The results indicated that the oil saturation of shale core samples rapidly increased in the first 16 days under the conditions of 60 °C and 30 MPa and then tended to plateau. The maximum oil saturation could reach 46.2% after a vacuum and pressurization duration of 20 days. After saturation, three distinct regions were identified on the T1–T2 NMR spectra of the shale core samples, corresponding to kerogen, organic pores (OPs), and inorganic pores (IPs), respectively. The oil trapped in IPs was the primary target for CO2 huff-n-puff in shale with a maximum cumulative oil recovery (COR) of 70% original oil in place (OOIP) after three cycles, while the oil trapped in OPs and kerogen presented challenges for extraction (COR < 24.2% OOIP in OPs and almost none for kerogen). CO2 preferentially extracted the accessible oil trapped in large IPs, while due to the tiny pores and strong affinity of oil-wet walls, the oil saturated in OPs mainly existed in an adsorbed state, leading to an insignificant COR. Furthermore, COR demonstrated a linear increasing tendency with soaking pressure, even when the pressure noticeably exceeded the minimum miscible pressure, implying that the formation of a miscible phase between CO2 and oil was not the primary drive for CO2 huff-n-puff in shale.

Enhanced toxicity-free astaxanthin extraction from Haematococcus pluvialis via concurrent cell disruption and demulsification

The extraction of astaxanthin from Haematococcus pluvialis involves the utilization of petroleum-derived organic solvents or supercritical CO2, beset by safety concerns, high costs, and environmental sustainability limitations. This study, in contrast, employed a method involving the adjustment of salt concentration, propylene glycol, and vegetable oil fraction to disrupt emulsion in aqueous cell lysates for facilitating the separation of astaxanthin. Under optimized conditions, an astaxanthin-containing oil with a content of 1.88% was obtained even with the use of wet biomass, and four rounds of consecutive extraction resulted in a cumulative recovery yield of 66.41%. This process produced astaxanthin-enriched soybean oil with 9.49 times improved antioxidant capacity that satisfies a requirement for health functional application. Omitting the solvent removal and drying processes, which consume tremendous energy, can reduce the production cost by 2.98 times compared to conventional methods. Consequently, this study suggests an effective technique for producing edible oil containing H. pluvialis-derived astaxanthin.

Design of corresponding fracturing parameters based on thin sand reservoir characteristics

Abstract China’s onshore oil fields have entered the late stage of development, while the reserves of thin-poor layers account for a large proportion of the remaining recoverable reserves. The development of thin-poor reservoirs has become an important potential for tapping potential. In this paper, the numerical simulation method is used to optimize the crack radius corresponding to the fracturing of the thin-poll injection-production system. The optimization results show that the fractured radius of the well has a greater impact on the final cumulative oil production and recovery when the fractured radius does not break the permeability boundary for a thin reservoir with a fracture penetration ratio of water and oil wells between 35% and 45%. when the oil well is in the high permeability area and the water well is in the low permeability area, the fractured radius of the well and the surrounding area of the oil well are used. The situation has a greater impact on the final oil production.

Evaluation of completing horizontal oil wells with inflow control devices

Oil production in horizontal wells currently has challenges such as excessive water production, which reduces the cumulative oil recovery, this occurs due to water coning in the reservoir which resulted to earlier water breakthrough in the wellbore. Various Down hole Flow control Devices (DFCs) including ICDs, AICDs, and AICVS are typically installed in the horizontal section of oil wells to mitigate the problem. The study of autonomous ICDs was done by comparing the long term flow performance of such devices against passive ICDs. The study was carried out with a reservoir model representing one horizontal well with three completion alternatives: open hole, ICD, and AICDs which were perforating in numerical reservoir model, these cases were run in the Eclipse simulator and their results were compared with the open hole. The results showed that the installation of Autonomous ICDs (AICDs) allowed producing more oil when compared against using passive ICDs. As it was found in three cases, for well X2, production with AICD increased the overall oil recovery by 257% and reduction of water cut to 42% as compared against an open hole completion, whereas production with ICD increased the overall oil recovery by 192% and reduction of water cut to 50% as compared against an open hole completion. The results proved that the installation of ICDs increased the net revenue comparing to open hole completion.

A Combined Neural Network Forecasting Approach for CO2-Enhanced Shale Gas Recovery

Summary Intensive growth of geological carbon sequestration has motivated the energy sector to diversify its storage portfolios, given the background of climate change mitigation. As an abundant unconventional reserve, shale gas reservoirs play a critical role in providing sufficient energy supply and geological carbon storage potentials. However, the low recovery factors of the primary recovery stage are a major concern during reservoir operations. Although injecting CO2 can resolve the dual challenges of improving the recovery factors and storing CO2 permanently, forecasting the reservoir performance heavily relies on reservoir simulation, which is a time-consuming process. In recent years, pioneered studies demonstrated that using machine learning (ML) algorithms can make predictions in an accurate and timely manner but fails to capture the time-series and spatial features of operational realities. In this work, we carried out a novel combinational framework including the artificial neural network (ANN, i.e., multilayer perceptron or MLP) and long short-term memory (LSTM) or bi-directional LSTM (Bi-LSTM) algorithms, tackling the challenges mentioned before. In addition, the deployment of ML algorithms in the petroleum industry is insufficient because of the field data shortage. Here, we also demonstrated an approach for synthesizing field-specific data sets using a numerical method. The findings of this work can be articulated from three perspectives. First, the cumulative gas recovery factor can be improved by 6% according to the base reservoir model with input features of the Barnett shale, whereas the CO2 retention factor sharply declined to 40% after the CO2 breakthrough. Second, using combined ANN and LSTM (ANN-LSTM)/Bi-LSTM is a feasible alternative to reservoir simulation that can be around 120 times faster than the numerical approach. By comparing an evaluation matrix of algorithms, we observed that trade-offs exist between computational time and accuracy in selecting different algorithms. This work provides fundamental support to the shale gas industry in developing comparable ML-based tools to replace traditional numerical simulation in a timely manner.

Laboratory Investigation on Permeability Change and Economic Analysis Using Some Selected Nanoparticles for Enhanced Oil Recovery

Enhanced oil recovery using nanoparticles is an emerging technique that can potentially alter permeability and wettability of porous media for improved oil mobilization. This study experimentally investigates the permeability alteration caused by three commonly used nanoparticle types – copper (ii) oxide, zinc oxide and silicon oxide. Core flooding experiments were conducted on reservoir rock samples before and after treatment with nanoparticle dispersions. Results show decrease in permeability by 35% for copper (ii) oxide, 30% for zinc oxide and 10% silicon oxide respectively. Pore-scale analysis indicates that permeability change occurs through mechanisms like pore throat blocking/wettability alteration. Nanoparticle concentration is also found to influence the permeability variation, with optimal dosage. Among the systems tested, Silicon oxide is the most effective formulation for enhancing oil recovery applications based on its ability to recover oil with minimal alteration to formation permeability. From the result, Silicon oxide had a cumulative recovery of 17ml, 18.0ml and 18.5ml thereby generating a percentage recovery of 73.91%, 78.26% and 80.43% while Zinc oxide had a cumulative recovery of 15.5ml, 18.0ml and 16.5ml thereby generating a percentage recovery of 77.50%, 78.26% and 71.74ml%, lastly Copper (ii) oxide had a cumulative recovery of 16.5ml, 17.0 and 16.0 generating a percentage recovery of 75%, 73.91% and 72.72% respectively with a concentration of 0.1%, 0.3%, and 0.5%. This study demonstrates the potential of Silicon oxide nanoparticles for enhanced oil recovery through permeability manipulation in porous media, however, the economic analysis shows that it’s quite expensive due to its cost of production and won’t be ideal for use. Hence Zinc oxide which also has a high volume of oil recovery, and less production cost can be used.

Evaluation of N nutrition and optimal fertilizer rate for ridge-furrow mulched maize based on critical N dilution curve under different water conditions

Optimizing nitrogen (N) management based on the critical N dilution curve (NCDC) has been proven a precision fertilization strategy to diagnose crop N nutrition status. However, few explorations have been done to establish a NCDC for dryland maize under double ridge-furrow mulching, a planting system that has been widely adopted in semi-arid areas. Moreover, the influences of various rainfall conditions on NCDC remain unclear. Therefore, a 9-yr field nitrogen fertilization experiment from 2013 to 2021 (five nitrogen rates: 0, 75, 150, 225, and 300 kg N ha–1, respectively, represented by N0, N0.25, N0.50, N0.75, and N1) was applied to established the NCDC under two planting systems (Flatting without mulching, CK; Double ridge-furrow with mulching, DRFM) and two rainfall types (rainfall season and drought season). Compared with CK, DRFM significantly increased plant dry matter (PDM, 5.5–12.8%) and N concentration (4.2–6.9%), ultimately improved grain yield (+16.9%), cumulative nitrogen recovery efficiency (CNRE, +9.8%) and crop water productivity (WPc, +26.3%). Rainfall from jointing to silking stage was an important contributor to grain yield. Compared with rainy season, drought season triggered a 51.7% yield loss and 17.1% reduction in NRE, respectively. The NCDC of the CK and DRFM were Nc=36.6×PDM−0.37 and Nc=38.4×PDM−0.36 in rainy season, respectively; the NCDC of the CK and DRFM were Nc =34.5×PDM−0.27 and Nc=37.3×PDM−0.30 in drought season, respectively. The nitrogen nutrition index (NNI) and plant nitrogen requirement (PNR) based on the NCDC intuitively recorded the N nutritional status. The improved soil micro-environment, PDM and N uptake was recorded in N0.75 (225 kg N ha–1 yr–1) under wet season and in N0.50 (150 kg N ha–1 yr–1) under drought season, respectively, which brought an increase in crop productivity with a suitable N nutrition status. The findings highlight an accurate and effective method for assessing the N nutrition status of rainfed maize, and optimize fertilization strategy for sustainable production in semi-arid regions.