Search Results (119)

The ZN Oilfield shale reservoir is characterized by thin sand–shale interbeds, strong lateral and vertical heterogeneity, poor porosity–permeability, low formation pressure coefficient, and low brittleness, which together limit fracture propagation and suppress production after conventional hydraulic fracturing. To overcome these constraints, we propose an intensive-stage, closely spaced volumetric fracturing technology that couples energy-replenishment pressurization with differentiated parameter design. Numerical simulations were used to quantify how injected fluid volume affects the post-fracturing formation pressure coefficient and estimated ultimate recovery (EUR), and to determine economically optimal energy-replenishment scales. Guided by a “dual sweet spot” evaluation (geological + engineering), field designs reduced stage spacing from 80–100 m to 30–50 m and cluster spacing from 10–20 m to 6–10 m, and increased proppant and fluid intensities to ~5.0 t/m and 22.0 m³/m, respectively. Field monitoring and production data show average fracture half-length increased to 193 m, and average initial oil production per well rose from 8.8 t/d to 12.9 t/d (≈46% increase). These results demonstrate that the proposed approach effectively enlarges fracture-controlled reservoir volume, enhances formation energy, and substantially improves single-well performance in low-pressure shale oil systems. Full article

This study addresses the challenges of low-pressure oil well workover operations, namely, severe loss of water-based workover fluid, significant reservoir damage from conventional temporary plugging agents, and slow production recovery, by focusing on the yet-mechanistically unclear “fuzzy-ball workover fluid.” Laboratory experiments combined with field data were used to evaluate its plugging performance and reservoir-protective mechanisms. In sand-filled tubes (diameter 25 mm, length 20–100 cm) sealed with the fuzzy-ball fluid, the formation’s bearing capacity increased by 3.25–18.59 MPa, showing a positive correlation with the plugging radius. Compatibility tests demonstrated that mixtures of crude oil and workover fluid (1:1) or crude oil, workover fluid, and water (1:1:1) held at 60 °C for 80 h exhibited only minor apparent viscosity reductions of 4 mPa·s and 2 mPa·s, respectively, indicating good stability. After successful plugging, a 1% ammonium persulfate solution was injected for 2 h to break the gel; permeability recovery rates reached 112–127%, confirming low reservoir damage and effective gel-break de-blocking. Field data from five wells (formation pressure coefficients 0.49–0.64) showed per-well fluid consumption of 33–83 m³ and post-workover liquid production index recoveries of 5.90–53.30%. Multivariate regression established mathematical relationships among bearing capacity, production index recovery, and fourteen geological engineering parameters, identifying the plugging radius as a key factor. Larger radii enhance both temporary plugging strength and production recovery without harming the reservoir, and they promote production by expanding the cleaning zone. In summary, the fuzzy-ball workover fluid achieves an integrated “high-efficiency plugging–low-damage gel-break–synergistic cleaning” mechanism, resolving the trade-off between temporary-plugging strength and production recovery in low-pressure wells and offering an innovative, environmentally friendly solution for the sustainable and efficient exploitation of oil–gas resources. Full article

Oil sands drilling frequently contaminates water-based xanthan gels with highly viscous asphaltenes, collapsing their three-dimensional network and causing barite sag, high fluid loss and poor cuttings transport. Nitrogen-functionalized carbon quantum dots (N-CQDs) were hydrothermally synthesised from citric acid and 1-hexadecylamine and characterised by means of FT-IR, TEM and TGA. The concentration-dependent influence of N-CQDs (0–1.2 wt%) on gel viscoelasticity, microstructure and filtration properties was evaluated through rheometry, API and fluid-loss tests. At 0.01 wt% N-CQDs, the viscosity of the adsorbed oil phase dropped by 50% and the mean droplet diameter decreased from 247.7 µm to <100 µm. Consequently, the xanthan gel exhibited a significant enhancement in its mechanical strength and fluid loss performance. Wax-crystal growth was simultaneously inhibited, lowering the pour point by 6 °C. N-CQDs act as nanospacers that disrupt π-stacking of asphaltenes and hydrogen-bond to the polymer backbone, thereby restoring gel strength and sealing capacity. The work provides a sustainable, low-toxicity route to rejuvenate gel-based drilling fluids contaminated by heavy oil and facilitates their reuse in oil sands reservoirs. Full article

Electromagnetic heating (EMH) using microwaves has emerged as a promising enhanced oil recovery (EOR) technique, particularly for heavy crude oils where conventional thermal methods encounter technical and environmental challenges. However, its large-scale implementation remains limited due to incomplete understanding of its energy transfer mechanisms. This study proposes an experimental–numerical approach integrating magnetic graphene oxide nanoparticles (Fe₃O₄@GO) with microwave heating to enhance energy absorption near the wellbore. The nanomaterial was synthesized via a modified Hummer’s method followed by in situ magnetite precipitation and studied through multiple material characterization techniques showing uniform 80 nm particles with superparamagnetic behavior—ideal for EMH applications. Nine experiments were conducted on sand–heavy-oil–water systems with nanoparticle concentrations up to 500 ppm using a laboratory microwave heating prototype. A simulation model was then developed in CMG-STARS for history matching to estimate energy absorption as a function of saturation and nanoparticle concentration. Experiments reached temperatures up to 240 °C, with 653 MJ of effective heat transferred to the target zone over 55 h, as estimated from the input heat required in the simulator for history matching. The results confirm that magnetic graphene oxide nanoparticles enhance thermal efficiency and heat distribution in microwave-assisted EOR. Full article

During the development of oil and gas fields, the plugging problem in the wellbore and near-wellbore area is a key factor affecting oil recovery efficiency and economic benefits. This paper systematically reviews the research progress on the formation mechanisms, influencing factors, and plugging removal technologies of four common types of plugging, namely wax plugging, scaling, sand plugging, and hydrate plugging. Studies show that plugging is the result of the coupling of multiple physicochemical processes, and is jointly affected by multiple factors such as fluid properties, temperature and pressure conditions, flow rate, and surface properties. Currently, the plugging removal technology has formed a synergistic system of multiple methods including chemical, physical, mechanical, and thermodynamic approaches; however, it still faces challenges such as limited treatment depth, high cost, and risk of secondary damage. In the future, efforts should be made to strengthen research on multi-scale plugging mechanisms and develop environmentally friendly and high efficiency plugging removal agents as well as intelligent monitoring technologies, so as to improve the reliability and economy of complex oil and gas resource development. This paper aims to provide theoretical support and technical directions for researchers and engineers, and promote the innovation and development of efficient oil and gas field development and flow assurance technologies. Full article

HPAM-Cr³⁺ (partially hydrolyzed polyacrylamide-chromium ion) gels are widely used in enhancing oil recovery (EOR) due to their advantages of low cost, controllability, and high strength. The propagation distance of gels within the reservoir significantly negatively impacts their gelation performance. However, the extent of this influence remains unclear, hindering precise optimization for field applications. This study first established a gelation performance characterization method based on visual inspection, rheological parameters, and long-term stability, accurately classifying gels into five types: stable strong gel (SSG), stable weak gel (SWG), colloidal dispersion gel (CDG), unstable gel (USG), and over-crosslinked gel (OCG). Subsequently, cross-experiments were conducted using varying concentrations of HPAM and Cr³⁺. Based on the contour map of visual appearance, storage modulus (G′), and water loss rate (R_w) of the gels, distribution maps of gel morphology versus concentration were constructed. The gel performance was found to depend on the HPAM concentration and the crosslinking ratio (molar ratio of HPAM carboxyl groups to Cr³⁺ ions). No gel formation occurred when the HPAM concentration was below 800 mg/L, while concentrations above 2500 mg/L effectively inhibited over-crosslinking. The crosslinking ratio range for forming SSG was 5.56 to 18.68, with an optimal value of 9.27. Furthermore, the effect of propagation distance on gelation performance was investigated through 60 m sand-packed flow experiments. Results indicated that the minimum value of the crosslinking ratio was 2.632, the stable SSG formed when the propagation distance was less than 21 m, SWG formed within the 21–34 m range, and no intact gel formed beyond 34 m. It means that only the first 35% of the designed distance formed effective SSG for plugging. Finally, an optimization method for gel dosage design was established based on the findings. This method determines the optimal gel dosage for achieving effective plugging by calculating the volume of crosslinking system passing through the target fluid diversion interface and referencing the gel morphology distribution maps. These findings provide a straightforward and effective approach for the precise design of in-depth profile control agents. Full article

Solvent-assisted steam-assisted gravity drainage (SA-SAGD) is an advanced hybrid oil recovery technique designed to enhance the extraction of heavy oil and bitumen. Unlike the conventional SAGD process, which relies solely on thermal energy from injected steam, SA-SAGD incorporates a coinjected solvent phase to improve oil mobility through the combined action of heat and mass transfer. This synergistic mechanism significantly reduces the demand for water and natural gas used in steam generation, thereby improving the energy efficiency and environmental sustainability of the process. Importantly, SA-SAGD retains the same well pair configuration as SAGD, meaning that its implementation often requires minimal modifications to existing infrastructure. This study explores the residual oil saturation following multi-component solvent coinjection in SA-SAGD using a linear sand pack model designed to emulate the properties and operational parameters of the Long Lake reservoir. Experiments were conducted with varying constant concentrations of cracked naphtha and gas condensate to assess their effectiveness in enhancing bitumen recovery. The results reveal that the injection of 15 vol% cracked naphtha achieved the lowest residual oil saturation and the highest rate of oil recovery, indicating superior solvent performance. Notably, gas condensate at just 5 vol% concentration outperformed 10 vol% cracked naphtha, demonstrating its effectiveness even at lower concentrations. These findings provide valuable insight into the phase behaviour and recovery dynamics of solvent–steam coinjection systems. The results strongly support the strategic selection of solvent type and concentration to optimise recovery efficiency while minimising steam consumption. Furthermore, the outcomes offer a robust basis for calibrating reservoir simulation models to improve the design and field-scale application of SA-SAGD, particularly in pilot operations such as those conducted by Nexen Energy ULC in the Athabasca Oil Sands. Full article

The E reservoir in Daqing Oilfield exhibits strong heterogeneity, resulting in inconsistent performance of conventional development methods. Polymer flooding is currently implemented using 106 m and 150 m well patterns. To characterize the influence of well spacing variations on polymer flooding effectiveness and enhance oil recovery, we conducted experiments to evaluate the apparent viscosity, solution concentration, viscoelasticity, plugging resistance, and profile modification performance of polymer solutions at different relative migration distances. Subsequent experiments employing differently scaled intra-layer heterogeneous models investigated polymer flooding’s oil recovery enhancement at various migration distances. Results indicate the following: (1) At identical relative migration distances, polymer systems in shorter sand-packed tubes demonstrate a higher effective migration distance proportion and superior viscoelasticity compared to 30 cm models, enabling more effective remaining oil mobilization and improved microscopic displacement efficiency. (2) The 20 cm sand-packed tube model exhibits enhanced plugging resistance and profile modification capabilities with higher maintained viscosity and concentration retention. Polymer solutions at 20%, 40%, 60%, and 80% migration distances in longer tubes established resistance factors of 30, 15, 7.8, and 3.6, and residual resistance factors of 9.6, 5.6, 2.2, and 1.5, respectively. These solutions effectively migrate to reservoir depths, forming efficient plugs and demonstrating superior deep profile control compared to their longer tube counterparts. (3) Polymer flooding response occurred at 0.194 PV injection in the 40 cm model with a maximum water cut reduction of 36.04%, whereas the 60 cm model required 0.31 PV injection to achieve a response, yielding only a 26.7% maximum water cut reduction. This comparative result demonstrates that smaller well spacing enables faster establishment of effective displacement pressure systems, suppresses high-permeability layer channeling, and significantly improves medium- and low-permeability layer utilization efficiency. (4) Crude oil mobilization in medium- and low-permeability layers is substantially reduced in larger well-spacing models. Collectively, reduced well spacing accelerates polymer flooding response, mitigates reservoir heterogeneity impacts, and extends the operational range of polymer plugging resistance and profile modification capabilities, thereby increasing recovery in heterogeneous reservoirs. Full article

To overcome the production bottleneck induced by the high viscosity of extra-heavy oil and resolve the issues of limited efficiency in traditional thermal oil recovery methods (including cyclic steam stimulation (CSS), steam flooding, and steam-assisted gravity drainage (SAGD)) as well as the fragmentation of existing viscosity reducer evaluation systems, this study establishes a multi-dimensional evaluation system for the effectiveness of viscosity reducers, with stage-averaged remaining oil saturation as the core benchmarks. A “1D static → 2D dynamic → 3D synergistic” progressive sequential experimental design was adopted. In the 1D static experiments, multi-gradient concentration tests were conducted to analyze the variation law of the viscosity reduction rate of viscosity reducers, thereby screening out the optimal adapted concentration for subsequent experiments. For the 2D dynamic experiments, sand-packed tubes were used as the experimental carrier to compare the oil recovery efficiencies of ultimate steam flooding, viscosity reducer flooding with different concentrations, and the composite process of “steam flooding → viscosity reducer flooding → secondary steam flooding”, which clarified the functional value of viscosity reducers in dynamic displacement. In the 3D synergistic experiments, slab cores were employed to simulate the SAGD development process after multiple rounds of cyclic steam stimulation, aiming to explore the regulatory effect of viscosity reducers on residual oil distribution and oil recovery factor. This novel evaluation system clearly elaborates the synergistic mechanism of viscosity reducers, i.e., “chemical empowerment (emulsification and viscosity reduction, wettability alteration) + thermal amplification (steam carrying and displacement, steam chamber expansion)”. It fills the gap in the existing evaluation chain, which previously lacked a connection from static performance to dynamic displacement and further to multi-process synergistic adaptation. Moreover, it provides quantifiable and implementable evaluation criteria for steam–chemical composite flooding of extra-heavy oil, effectively releasing the efficiency-enhancing potential of viscosity reducers. This study holds critical supporting significance for promoting the efficient and economical development of extra-heavy oil resources. Full article

Understanding the fluid storage and production mechanisms in sedimentary rocks is vital for optimising natural gas extraction and subsurface resource management. This study applies high-resolution X-ray computed tomography (≈15 μm) to digitise rock samples from onshore Cyprus, producing digital rock models from DICOM images. The workflow, including digitisation, numerical simulation of natural gas flow, and experimental validation, demonstrates strong agreement between digital and laboratory-measured porosity, confirming the methods’ reliability. Synthetic sand packs generated via particle-based modelling provide further insight into the gas storage mechanisms. A linear porosity–permeability relationship was observed, with porosity increasing from 0 to 35% and permeability from 0 to 3.34 mD. Permeability proved critical for production, as a rise from 1.5 to 3 mD nearly doubled the gas flow rate (14 to 30 fm³/s). Grain morphology also influenced gas storage. Increasing roundness enhanced porosity from 0.30 to 0.41, boosting stored gas volume by 47.6% to 42 fm³. Although based on Cyprus retrieved samples, the methodology is applicable to sedimentary formations elsewhere. The findings have implications for enhanced oil recovery, CO₂ sequestration, hydrogen storage, and groundwater extraction. This work highlights digital rock physics as a scalable technology for investigating transport behaviour in porous media and improving characterisation of complex sedimentary reservoirs. Full article

An integrated approach to waste management is based on efficient and safe methods for waste prevention, recycling, and safe waste treatment. In accordance with these principles, in this study, non-hazardous aluminosilicate waste (dust and sand) was used in the solidification/stabilization (S/S) treatment of hazardous waste (coating, emulsion, and sludge) from the automotive industry. Also, the oily component of the waste was valorized and investigated for energy recovery through co-incineration. The two S/S processes were proposed and their sustainability was assessed by utilizing all types of waste generated in the same plant, obtaining stabilized material suitable for safe disposal and oil phases for further valorization, and by techno-economic analysis. The efficiency of the S/S processes was evaluated by measuring unconfined compressive strength, hydraulic conductivity, density, and the EN 12457-4 standard leaching test of S/S products, along with XRD, SEM-EDS, and TG-DTG analyses. The possibility of using the oil phase was assessed based on its calorific value. The techno-economic assessment compared the investments, operating costs, and potential savings of both treatment scenarios. The results show that an integrated approach enables safe waste immobilization and resource recovery, contributing to environmental protection and economic benefits. Full article

Microbial-enhanced oil recovery (MEOR) is a promising technology for oilfield development. To improve MEOR efficiency, two functional strains—Bacillus mucilaginosus ZZ-8 and Bacillus amyloliquefaciens ZZ-11—were isolated and purified. The growth characteristics, biosurfactant production, and crude oil emulsification performance of these strains were systematically evaluated through single-strain cultures and a co-culture system (ZZ-8: ZZ-11 = 1:1). The results demonstrated that the co-culture system exhibited superior growth and functional performance compared to monocultures. The cell-free supernatant significantly reduced oil–water interfacial tension, decreasing the contact angle from 53.56 ± 1.3° to 28.78 ± 0.82°, thereby enhancing crude oil detachment from rock surfaces and improving oil displacement efficiency. Gas chromatography (GC) analysis further confirmed the co-culture system’s pronounced degradation of long-chain alkanes (C17–C35). In oil sand washing experiments, the 1:1 mixed-strain fermentation broth achieved a crude oil elution rate of 84.39%, representing an 89.80% increase over uninoculated medium. This study not only validates the synergistic effect of the B. mucilaginosus–B. amyloliquefaciens co-culture system in enhancing oil recovery but also provides a theoretical foundation and innovative strategy for its practical application in MEOR technology. Full article

Meandering river point bar sand bodies, serving as critical reservoir units, exhibit significant lithofacies heterogeneity that governs remaining oil distribution patterns. Taking the Guantao Formation in the Gudao Oilfield as an example, this study integrates core observation, pore-throat structure characterization, and numerical simulation to reveal lithofacies characteristics of point bar sand bodies and their controlling mechanisms on incremental oil recovery distribution during surfactant–polymer (SP) flooding. The results demonstrate that point bar lithofacies display planar grain-size fining from concave to convex banks, with vertical upward-fining sequences (point bar medium sandstone facies → fine sandstone facies → siltstone facies). Physical property variations among lithofacies lead to remaining oil enrichment in relatively low-permeability portions of fine sandstone facies and low-permeability siltstone facies after waterflooding. SP flooding significantly enhances remaining oil mobilization through a “lithofacies-controlled percolation—chemical synergy” coupling mechanisms. The petrophysical heterogeneity formed by vertical lithofacies assemblages in the reservoir directly governs the targeted zones of chemical agent action (with interfacial tension reduction preferentially occurring in high-permeability lithofacies, while viscosity control dominates sweep enhancement in low-permeability lithofacies). This results in a distinct spatial differentiation of the incremental oil recovery, characterized by a spindle-shaped sweep improvement zone and a dam-type displacement efficiency enhancement zone. Full article

A CO₂-responsive TMPDA–SDS–SiO₂ gel system was developed and evaluated through formulation optimization, structural characterization, rheological testing, and core flooding experiments. The optimal formulation was identified as 7.39 wt% SDS, 1.69 wt% TMPDA, and 0.1 wt% SiO₂, achieving post-CO₂ viscosities above 10³–10⁴ mPa·s. Spectroscopic and microscopic analyses confirmed that CO₂ protonates TMPDA amine groups to form carbamate/bicarbonate species, which drive the micellar transformation into a wormlike network, thereby enhancing gelation and viscosity. Rheological tests showed severe shear-thinning behavior, excellent shear recovery, and reversible viscosity changes under alternating CO₂/N₂ injection. The gel demonstrated rapid responsiveness, reaching stable viscosities within 8 min, and maintained good performance after 60 days of thermal aging at 90 °C and in high-salinity brines. Plugging tests in sand-packed tubes revealed that a permeability reduction of 98.9% could be achieved at 0.15 PV injection. In heterogeneous parallel core flooding experiments, the gel preferentially reduced high-permeability channel conductivity, improved sweep efficiency in low-permeability zones, and increased incremental oil recovery by 14.28–34.38% depending on the permeability contrast. These findings indicate that the CO₂-responsive TMPDA–SDS–SiO₂ gel system offers promising potential as a novel smart blocking gel system for improving the effectiveness of CO₂ flooding in heterogeneous reservoirs. Full article

Anthropogenic disturbances interact with wildfire, altering successional dynamics across North America’s boreal forest. Linear disturbances, including seismic lines used for oil and gas exploration, dissect forests, while wildfire is a fundamental agent of forest succession. However, little is known about early succession dynamics after both seismic line creation and wildfire, especially across transitions from uplands to peatlands. To address this, we characterized and compared regeneration and recruitment after individual and successive disturbances in peatland, transitional, and mesic upland forests across the oil sands region of Alberta, Canada. We used non-metric multidimensional scaling to compare composition and mixed-effects generalized linear models to compare densities of trees and tall shrubs 10 to 24 years after disturbance. Compositionally, regeneration was similar within forest types and between transitional and peatland forests, while patterns in recruitment were more influenced by past disturbances. Overall, we found evidence of dominant, additive, and interactive effects on early successional patterns within linear disturbances in boreal forests. In transitional and peatland forests, disturbances influenced tree and tall shrub regeneration and recruitment in complex ways. Early successional dynamics after disturbance influence forest structure and composition and are vital to understanding recovery in boreal forests, especially across boreal forest transitions. Full article