Search Results (486)

The reuse of treated oilfield-produced water (PW) presents a viable solution to water scarcity in arid regions; however, elevated boron (B) levels pose a significant constraint for sustainable irrigation. This study evaluates boron dynamics in a soil–plant system irrigated with treated PW and examines the effectiveness of nature-based solutions in mitigating its accumulation. A controlled experiment using two soil types and multiple water sources was conducted, with biochar and gypsum applied as soil amendments. Boron concentrations were assessed in plant tissues, roots, and soil layers. Results showed significant boron accumulation under PW irrigation, exceeding safe agronomic thresholds, and soil analysis indicated greater boron retention in surface layers. Boron concentrations reached maximum average concentrations exceeding 200 mg kg⁻¹. To elucidate species-specific tolerance mechanisms, bioaccumulation factors (BAFs) and translocation factors (TFs) were calculated. Results revealed a distinct root-trapping strategy, with high BAF values under oilfield-produced water, while TF values remained significantly lower, indicating that these forage species successfully restricted boron translocation to aerial tissues. Full article

Remaining oil in high-water-cut reservoirs becomes increasingly dispersed during long-term waterflooding, while preferential flow paths cause severe ineffective water circulation and reduce the efficiency of further oil displacement. To improve the quantitative identification of remaining oil enrichment and water-flushed regions, this study proposes a displacement-unit-based classification and evaluation method for dominant remaining oil distribution. The method integrates dynamic allocation of injected water in multilayer reservoirs, time-varying characterization of reservoir physical properties, streamline-based delineation of displacement units, and saturation tracking using the φ-function. Two quantitative indicators, the remaining oil abundance index (I_so) and the water flushing intensity coefficient (C_f), were introduced to classify displacement units into strongly dominant, weakly dominant, and non-dominant types. The method was applied to a high-water-cut block of the W Oilfield, where 902 displacement units were identified from 65 oil and water wells and 36 sublayers. The results show that strongly dominant, weakly dominant, and non-dominant displacement units accounted for 37.9%, 33.7%, and 28.4% of the total, respectively. In 15 sublayers, the proportion of strongly dominant units exceeded 50%, indicating severe preferential water flow and limited remaining oil potential in these layers. Strongly dominant units were characterized by high water flushing intensity and low remaining oil abundance, whereas weakly dominant units showed remaining oil enrichment mainly at the margins of displacement units. The proposed method couples injection–production dynamics with seepage-field evolution and provides a quantitative basis for fine-scale adjustment of injection–production patterns in high-water-cut reservoirs. Full article

Precise forecasting of the initial productivity rates of infill wells is essential for the effective exploitation of offshore reservoirs characterized by high water-cut. However, conventional reservoir simulation and basic machine learning models often suffer from high computational complexity and low interpretability. This research introduces a hybrid data-driven framework that combines ensemble feature engineering with a random forest model optimized through the crayfish optimization algorithm. The primary controlling factors were identified through a majority voting mechanism involving five feature selection algorithms. Subsequently, the COA was utilized to optimize the parameters of the random forest algorithm to improve its predictive robustness. The proposed EFE-COA-RF model achieves a testing MAE of 6.831 and an R² of 0.954, outperforming standard machine learning models and other optimization-based variants. The complete training process requires approximately 10.8 min, whereas the prediction time for the testing set is approximately 0.03 s. These results demonstrate that the proposed framework provides an accurate, interpretable, and efficient tool for rapid productivity evaluation in mature offshore oilfields. Full article

Fracture–vuggy carbonate reservoirs contain discrete caves, fractures, conduits, and vugs, which makes recoverable-reserve evaluation strongly dependent on connected volume rather than on total pore volume alone. This study develops a unit-scale dynamic reserve-updating method for the S48 unit, Tahe Oilfield, by coupling a water-body-corrected material-balance equation, a heterogeneity-corrected waterflood characteristic curve, and iterative geological-model calibration. The main methodological contribution is to convert static fracture–vug architecture into dynamically constrained connected subsystems: the parameter Rwo quantifies connected/injected water volume at the fracture–vug unit scale, whereas the coefficient M corrects the apparent slope of waterflood curves for non-uniform sweep and preferential pathways. The revised workflow was calibrated against pressure, production, injection-response, and history-matched simulation data. Sensitivity analysis indicates that the estimated reserve-utilization degree increased from 48.77% +/− 4.8 percentage points during natural depletion to 74.1% +/− 6.7 percentage points after gas injection, reflecting staged reserve mobilization within the tested uncertainty range. The method is intended for field-scale reserve updating in reservoirs with sufficient pressure-production data; its transferability remains limited by static-model quality, channeling intensity, and the single-unit validation scope of this study. Full article

Hydrolyzed polyacrylamide stabilized oil-in-water emulsions are highly persistent because the polymer strengthens both continuous-phase rheology and the oil–water interfacial film, making demulsification difficult in polymer-flooding produced liquids. Here, an hydrolyzed polyacrylamide degrading bacterium, Delftia lacustris EPDB-8, was isolated, and its ability to destabilize hydrolyzed polyacrylamide-containing emulsions was investigated from molecular, bulk rheological, and interfacial perspectives. EPDB-8 effectively degraded HPAM, causing marked reductions in total organic carbon, total nitrogen, absolute zeta potential, and polymer molecular weight, with an approximately 63-fold decrease after 7 days. SEM, FT-IR, and GPC analyses showed that biodegradation proceeded through deamidation and random chain scission, collapsing the polymer network and generating low-molecular-weight fragments. Driven by bacterial hydrolyzed polyacrylamide degradation, these structural alterations disrupted the viscoelastic composite interfacial film formed by hydrolyzed polyacrylamide and indigenous surface-active species, directly causing emulsion stabilization to shift from polymer-assisted viscous and steric protection to a less effective asphaltene-dominated interfacial structure and thereby accelerating droplet aggregation, coalescence, and phase separation. Although bacterial cells exerted a transient particle-assisted interfacial effect, long-term emulsion stability remained governed by polymer integrity. This study establishes a mechanistic link between hydrolyzed polyacrylamide biodegradation and the rheological and interfacial evolution governing emulsion breakdown, providing a cost-effective and environmentally benign biological strategy for demulsification and treatment of polymer-flooding produced water. These findings offer practical guidance for the design of microbial-based produced-water treatment systems and contribute to the sustainable management of oilfield wastewater generated during enhanced oil recovery operations. Full article

Corrosion and scaling critically threaten the safety and efficiency of oil–gas gathering stations. Through field inspections, water chemistry analysis, scale characterization, and corrosion simulation in Yanchang oilfield, this study identifies severe localized damage in key components—such as valves, bends, and injection pipelines—with service lives of only 1–2 years. Analysis of over 200 scale samples revealed that CaCO₃ (42 wt%) and CaSO₄ (23 wt%) were the predominant scale types. High salinity >56,000 mg/L, Cl⁻ >31,000 mg/L, and Ca²⁺ promote under-deposit pitting, galvanic corrosion (e.g., Cu–steel couples), and erosion-corrosion at high-velocity zones. Simulations based on OLI Analyzer Studio (a professional thermodynamic simulation software for electrolyte solution and high-salinity brine systems) reveal that the carbon steel (the primary material for the process pipelines and water injection pipelines in the studied oil–gas gathering and transportation stations) has a corrosion rate rising from 0.078 mm/year at 25 °C to 1.94 mm/year at 90 °C. Despite common use of coatings and cathodic protection, these measures often fail to address site-specific failure mechanisms. The study advocates a tailored mitigation strategy combining material compatibility, real-time water monitoring, optimized filtration, and component-level design. This integrated approach enhances asset reliability and operational safety in onshore oilfields. Full article

Offshore oil and gas exploitation is one of the riskiest businesses to invest in and is dominated by various uncertainties: high deepwater pressure, low temperatures, remote operation, long-distance tiebacks and transportation, as well as environmental factors such as wind, waves and ocean currents. Serving as a profitability threshold, the minimum economic field size is defined as the economic recoverable reserve level that an oilfield must exceed to achieve economic returns. This paper develops an approach for determining the minimum economic field size of offshore oil and gas reservoirs. It categorizes the capital expenditure into four major components: drilling and completion costs, platform costs, pipeline costs, and subsea production system costs. The regression models of drilling costs and subsea production costs are developed respectively, with water depth and recoverable reserves as key influencing factors. The pipeline costs are estimated using the unit pipeline cost per mile and pipeline length. A profit model for the offshore field is established under the constraints of the contract, which allocates the oilfield’s production profits between the contractor and the government according to the contractual fiscal terms. Finally, taking the Lucius oilfield in the Gulf of Mexico as a case study, the paper simulates its investment, operating costs, and oilfield revenues. The minimum economic field size is calculated, accompanied by the derivation of the sensitivity boundaries for the primary parameters. Full article

The physicochemical mechanisms and numerical characterization of amine-ether gemini surfactant emulsion flooding remain insufficient, limiting its field application in low-permeability reservoirs. This study developed a refined numerical simulation method that integrates full-process emulsion kinetics, including generation, coalescence, dispersion-assisted oil displacement, and demulsification, with graded emulsion characterization using the differentiated inaccessible pore volume (IPV) and residual resistance factor (RRF). Core-flooding validation demonstrated that the model accurately reproduced the key dynamic responses of water cut reduction and oil production increase, with a relative error of about 3.0%. Mechanistic analysis showed that the enhanced oil recovery performance arose from the combined effects of ultralow interfacial tension and emulsion-induced profile control. Relative to conventional surfactant flooding, emulsion flooding increased oil recovery by an additional 4.8–5.0% and lowered water cut by about 12 percentage points. For the Shengli Oilfield pilot block, the optimized injection design involved a surfactant concentration of 1.2 wt.%, an injection rate of 60 m³/d, a slug size of 0.01 PV, an injection–production ratio of 0.95, and a stepwise concentration-decline strategy. The field pilot further confirmed the applicability of the method: daily oil production of the well group increased by 46.5%, while comprehensive water cut decreased by 8.6 percentage points. These results demonstrate the value of the proposed method for both mechanistic characterization and field design of amine-ether gemini surfactant emulsion flooding in heterogeneous low-permeability reservoirs. Full article

In response to the challenges in monitoring the production profile during the development of the Qingcheng shale oil field in the Changqing Oilfield, this study systematically investigates the application mechanism and practical effectiveness of Distributed Temperature Sensing (DTS) technology for dynamic monitoring in horizontal wells. By establishing a coupled model of fracture–matrix dual-porosity media flow and wellbore thermodynamics, which integrates mass, momentum, and energy conservation equations solved via the finite difference method, an interpretation method for the production profile based on the Joule–Thomson effect is proposed. The model was calibrated using shut-in temperature data and validated by comparing simulated temperature profiles with DTS measurements under constant-rate production. Field tests conducted in six horizontal wells in the Qingcheng oil field enabled the quantitative analysis of cluster-level production contributions along the horizontal section, with a water-producing zone localization accuracy of ±3.5 m. The results indicate that shale oil wells exhibit a non-uniform production characteristic of “high at the front and low at the rear” during the early production stage, where the production contribution from fully fractured segments can be up to 2.8 times that of adjacent segments. Inversion of the fiber-optic monitoring data reveals that differences in the conductivity of hydraulic fractures are the primary cause of flow heterogeneity. This research provides a theoretical foundation and technical support for the efficient development of shale oil, contributing to the transition of China’s continental shale oil development from “experience-driven” to “data-driven.” Full article

Low-permeability reservoirs at the high-water-cut stage commonly suffer from dominant water channel development, poor sweep of weakly connected zones, and inefficient mobilization of remaining oil. Existing profile control or oil displacement agents can improve either flow diversion or microscopic oil displacement, but their single-agent evaluation does not fully explain the coupled process of sweep expansion and remaining oil mobilization. To address this issue, this study focuses on a previously optimized HK-0417/ALT-603 composite system and investigates its synergistic behavior at pore, core, and well group scales. Microscopic visualization displacement experiments were used to identify streamline redistribution and remaining oil evolution. Natural core experiments were conducted to evaluate injectivity adaptability and plugging persistence. Under slug injection conditions, the Box–Behnken design was employed to optimize the injection parameters. Finally, the field pilot response was analyzed based on production data from test wells in the Changqing Oilfield. The results show that the combination system simultaneously achieves streamline expansion and residual oil reduction: the injected fluid is redistributed toward weakly swept zones, large continuous oil bodies are fragmented and dispersed, and both sweep efficiency and oil displacement efficiency are superior to those of individual agents. Natural core experiments indicate that the injection pressure difference is generally controllable in cores with permeabilities ranging from 1.76 to 7.02 mD, and the plugging rate during subsequent water flooding reaches 75.47–80.54%. Response surface optimization yields the following optimal parameter combination: profile control slug volume = 0.41 pore volume (PV), oil displacement slug volume = 0.61 PV, injection rate = 0.19 mL/min, with a corresponding predicted enhanced oil recovery (EOR) of 18.52%. In the field pilot, the cumulative injection volumes of the two injectors are 41,898 kg and 61,472 kg, respectively. The injection pressure in the well group increases from 5.8 MPa to 7.0 MPa, the comprehensive water cut decreases from 90.6% to 85.3%, and the monthly decline rate is reduced from 0.5% to 0.2%. The proposed system mainly acts by increasing flow resistance and redirecting flow in high-water-cut channels, while it enhances oil detachment through interfacial tension reduction in oil-bearing pores. After optimizing the slug parameters, the field pilot exhibits a clear phased response and promising application potential. Full article

In the ultra-high water cut stage, unconsolidated sandstone reservoirs suffer from severe reservoir property time-variation, streamline solidification, and inefficient water circulation. To tackle these problems, this study takes Chengdao Oilfield Block 1G as an example and establishes a dynamic geological model considering permeability time-varying characteristics based on logging, core, and production data. The flow field intensity index and streamline solidification rate are introduced to quantitatively characterize the preferential flow channels and high water-consumption zones. Results show that long-term water flooding increases the average permeability by 26.88% and expands the interlayer permeability ratio from 10.33 to 19.00. The streamline solidification rate reaches 75%, forming obvious “short-circuit” circulation. Three remaining oil enrichment patterns are identified, which are mainly controlled by sedimentary microfacies, structural highs, and well pattern control. A differential regulation strategy including 3D well pattern reconstruction and streamline diversion is proposed. Field prediction indicates that the cumulative incremental oil can reach 410,000 tons and the recovery factor is enhanced by 1.3%. This study not only reveals the dynamic evolution mechanism of flow field under water-rock coupling effects but also provides a practical technical system for flow field regulation and remaining oil tapping in similar offshore ultra-high water-cut unconsolidated sandstone reservoirs. Full article

Recently, a substantial quantity of oil and gas has been discovered in the pre-salt Lower Cretaceous microbialite successions of Brazil’s Santos Basin, thereby prompting a global surge in research related to microbialites. It has been demonstrated that microbial shoal reservoirs yield the highest hydrocarbon production, with optimal reservoir properties, as evidenced by experience in the field of oilfield production. However, as research progresses, it has become increasingly evident that significant heterogeneity exists in both the lithology and physical properties within microbial shoal bodies. In order to address the identified knowledge gap, the present study employs systematic petrological and petrophysical datasets. These include 30-m continuous core samples, thin-section analyses, routine petrophysical tests and mercury injection capillary pressure (MICP) measurements. The aim is to characterize the internal microfacies architecture and reservoir heterogeneity of microbial shoals. It is imperative to ascertain the principal factors that govern the heterogeneity observed in these reservoirs. This critical step is essential for a comprehensive understanding of the subject matter. The results of the study demonstrate that: the Barra Velha Formation microbial shoals in the Santos Basin can be subdivided into three microfacies, which are delineated from base to top. The foundation of the shoal is the shoal base. The rock composition is dominated by the presence of spherulites, with intracrystalline pores functioning as the primary reservoir spaces. The compositional rocks of the shoal flank are poorly sorted microbial debris, with intergranular and intragranular pores formed by penecontemporaneous dissolution. The sedimentary succession of the shoal core is characterized by well-sorted microbial debris rocks displaying multiple shallowing-upward sequences, with reverse-graded textures. The primary storage space is constituted by fabric-selective pores from penecontemporaneous dissolution, though these are subject to local disruption by destructive silicification. Meanwhile, the microbial shoals demonstrate wide porosity (8.8–26.4%, mean 16.8%) and permeability (0.13–839 mD, mean 169 mD) ranges, thus classifying them as medium-porosity, high-permeability reservoirs. The superimposition of microfacies and diagenetic processes gives rise to considerable reservoir heterogeneity. It is evident that the shoal core microfacies exhibits robust energy and substantial grain size, characteristics that facilitate its exposure above lake level during periods of high-frequency lake-level oscillation. This exposure is further compounded by the influence of atmospheric water dissolution, which remodels the microfacies during the quasi-contemporaneous period. The reservoir quality is optimal, exhibiting the highest proportion of large pores. The reservoir properties of the shoal flank are closely followed by medium and large pores, and those of the shoal base are the worst, with micro and medium pores. Full article

In response to corrosion challenges encountered during the gathering and transportation of wet natural gas, this study systematically investigates the corrosion behavior of L245NCS steel in environments containing O₂, H₂S, CO₂ and simulated oilfield-produced water. The research employs a combined approach involving high-pressure autoclave experiments and transparent flow loop simulations. Autoclave tests reproduce gas phase, liquid phase, and gas–liquid interface conditions under a controlled O₂-H₂S-CO₂ mixture, while a visual flow loop equipped with elbows and undulating sections is used to examine liquid accumulation behavior and flow characteristics under dynamic, real-world operating conditions. Results indicate that corrosion is most severe at the gas–liquid interface. H₂S is identified as the primary corrosive agent, exerting a stronger influence than CO₂ or O₂. Liquid accumulation is the main factor leading to non-uniform corrosion distribution, and its formation is influenced by water content, pressure, temperature difference, and pipeline shutdown and restart operations. Critical areas such as low-lying sections, downhill bottoms, and the beginning of uphill sections exhibit localized corrosion rates up to 61.4% higher than areas without liquid accumulation. This integrated methodology bridges mechanistic understanding with engineering practice, providing a basis for corrosion risk assessment, optimal monitoring point placement, and integrity management of wet gas pipelines. Full article

The low separation efficiency of alkali/surfactant/polymer (ASP)-flooding-produced water, attributed to its high emulsification, high viscosity, and surfactant enrichment, presents a significant treatment challenge. To evaluate the effects of flotation unit structure on internal flow field characteristics and the separation performance of oil and suspended solids in a dissolved air flotation–sedimentation tank, this study conducted CFD numerical simulations. The results demonstrate that with 40 gas injection ports, the flow field achieves optimal uniformity and stability: the oil removal rate reaches 68.1%, and the suspended solids removal rate reaches 56.6%. Compared to the single-ring and triple-ring configurations, the double-ring gas injection form exhibits better flow continuity, resulting in increased removal rates of 67.6% for oil and 56.7% for suspended solids. At a gas injection ring height of 10,500 mm, the oil layer in the flotation zone remains continuous and stable, while suspended solids settle into a distinct sediment layer at the bottom, enhancing both oil and suspended solids removal efficiencies. On this basis, the optimized structure of the flotation unit was determined. The removal rates of oil and suspended solids were enhanced by approximately 1.8% to 4.8% and 3.5% to 7.0%, respectively, compared to the existing conditions. Full article

The produced water from the No. 1 Oil Production Plant of Xinjiang Oilfield is rich in divalent ions, including Ca²⁺, Mg²⁺, and SO₄²⁻, leading to extremely high scaling tendency that fails to meet the reinjection standard. Therefore, highly efficient water softening technology is urgently required for such wastewater treatment. In this study, a novel negatively charged nanofiltration (NF) membrane was fabricated via interfacial polymerization using 2-carboxypiperazine and trimesoyl chloride as monomers. The membrane was systematically characterized by scanning electron microscopy (SEM), X-ray photoelectron spectroscopy (XPS), and Fourier-transform infrared spectroscopy (FTIR), and its rejection performance was investigated under various conditions. Results show that the maximum rejection rates of the NF membrane reached 99% for SO₄²⁻, 81% for Ca²⁺, and 94% for Mg²⁺, respectively. With increasing ion concentration, the removal efficiencies of Ca²⁺ and Mg²⁺ decreased, while that of SO₄²⁻ increased slightly. Higher operating pressure significantly enhanced both ion removal and membrane flux, which was mainly attributed to the synergistic effects of Donnan electrostatic exclusion, membrane surface adsorption, and mass transfer resistance. When applied to treat real produced water from the No. 1 Oil Production Plant, the membrane achieved 100% removal of SO₄²⁻, and 91% and 95% removal of Ca²⁺ and Mg²⁺, respectively. The scaling tendency of the treated effluent was completely eliminated. This work provides theoretical and technical support for the engineering application of nanofiltration technology in oilfield wastewater treatment. Full article