Flooding Experiments Research Articles

Experimental Study on the Application of Polymer Agents in Offshore Oil Fields: Optimization Design for Enhanced Oil Recovery.

The Bohai oilfield is characterized by severe heterogeneity and high average permeability, leading to a low water flooding recovery efficiency. Polymer flooding only works for a certain heterogeneous reservoir. Therefore, supplementary technologies for further enlarging the swept volume are still necessary. Based on the concept of discontinuous chemical flooding with multi slugs, three chemical systems, which were polymer gel (PG), hydrophobically associating polymer (polymer A), and conventional polymer (polymer B), were selected as the profile control and displacing agents. The optimization design of the discontinuous chemical flooding was investigated by core flooding experiments and displacement equilibrium degree calculation. The gel, polymer A, and polymer B were classified into three levels based on their profile control performance. The degree of displacement equilibrium was defined by considering the sweep conditions and oil displacement efficiency of each layer. The effectiveness of displacement equilibrium degree was validated through a three-core parallel displacement experiment. Additionally, the parallel core displacement experiment optimized the slug size, combination method, and shift timing of chemicals. Finally, a five-core parallel displacement experiment verified the enhanced oil recovery (EOR) performance of discontinuous chemical flooding. The results show that the displacement equilibrium curve exhibited a stepwise change. The efficiency of discontinuous chemical flooding became more significant with the number of layers increasing and heterogeneity intensifying. Under the combination of permeability of 5000/2000/500 mD, the optimal chemical dosage for the chemical discontinuous flooding was a 0.7 pore volume (PV). The optimal combination pattern was the alternation injection in the form of "medium-strong-weak-strong-weak", achieving a displacement equilibrium degree of 82.3%. The optimal shift timing of chemicals occurred at a water cut of 70%, yielding a displacement equilibrium degree of 87.7%. The five-core parallel displacement experiment demonstrated that discontinuous chemical flooding could get a higher incremental oil recovery of 24.5% compared to continuous chemical flooding, which presented a significantly enhanced oil recovery potential.

Flood-driven survival and growth of dominant C4 grasses helps set their distributions along tallgrass prairie moisture gradients.

Five C4 grasses (Bouteloua curtipendula, Schizachyrium scoparium, Andropogon gerardii, Sorghastrum nutans, Spartina pectinata) dominate different portions of a moisture gradient from dry to wet tallgrass prairies in the Upper Midwest of the United States. We hypothesized that their distributions may partly reflect differences in flooding tolerance and context-specific growth relative to each other. We tested these ideas with greenhouse flooding and drought experiments, outdoor mesocosm experiments, and a natural experiment involving a month-long flood in two wet-mesic prairies. Bouteloua promptly succumbed to inundation, so flooding intolerance likely excludes it from wet and wet-mesic prairies. Competition is likely to exclude short-statured Bouteloua from productive mesic sites. Schizachyrium is excluded from wet prairies by low flooding tolerance, demonstrated by all experiments. Sorghastrum had low flooding tolerance in both greenhouse and natural experiments, suggesting that physiological intolerance excludes it from wet prairies. Spartina had by far the greatest growth under the wettest mesocosm conditions; this and comparisons of species growth in monocultures vs. mixtures suggests that competition helps it dominate wet prairies. Indeed, quadrat presence of Spartina increased by 57% two years after flooding of two prairies, while that of upland grasses declined by 44%. The high flooding tolerance, lack of significant differences from other species in drought tolerance, and tall stature of Andropogon suggest that broad physiological tolerance combined with competitive ability allows it to thrive across the prairie moisture gradient. Flooding helps shape the distributions of dominant prairie grasses, and its effects may become more important as extreme rain events continue to increase.

Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir

The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively because of small water flood sweep and large injection pressure. Pressure flooding is a new water injection technique that can change the reservoir pore space. Combined with an oil displacement agent, pressure flooding is expected to improve the recovery rate of carbonate reservoirs. In this paper, the influence factors of pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed. The results show that only an appropriate injection flow can produce microfractures. Only an appropriate displacement rate can optimize the effects of pressure flooding. With an increase in crude oil viscosity, the recovery rate after pressure flooding decreases gradually. A complex fracture network is formed in reservoirs after pressure flooding. The new surfactant system has good interfacial tension reduction properties and excellent stability. Pressure flooding experiments with the addition of a surfactant showed that the system can help to improve the recovery of pressure flooding.

Synthesis and oil displacement performance evaluation of asymmetric anionic gemini surfactants

In order to further enhance the water flooding performance in low-permeability tight oil reservoirs, a novel gemini surfactant with high interfacial activity, hydrophilic wettability, and good injectivity and mobility control was developed. Using n-alkylamine (C12–C18), 3-chloro-2-hydroxypropylsulfonate sodium, sodium chloroacetate, and succinic anhydride as raw materials, a series of gemini surfactants with asymmetric hydrophilic head groups (GDCS m-4-m; m = 12, 14, 16, 18) were synthesized via substitution and ring-opening reactions. The structures of the synthesized products were characterized by FTIR and 1H NMR, and their surface and interfacial properties as well as their thickening abilities were evaluated. The optimal gemini surfactant was selected for further oil displacement and wettability alteration tests. The results indicate that the synthesized product is consistent with the molecular structure of the target design product. The surface tension and interfacial tension of GDCS m-4-m series surfactant solutions initially decrease and then increase with the increase in the number of carbon atoms in the hydrophobic carbon chain. Its thickening ability increases as the number of carbon atoms in the hydrophobic carbon chain increases. GDCS16-4-16 exhibited the best surface and interfacial activities, with a critical micelle concentration (CMC) of 0.344 mmol/L, surface tension of 24.04 mN/m, and an interfacial tension as low as 2.16 × 10−2 mN/m at 0.5 wt%. The flooding system formulated with GDCS16-4-16 demonstrated excellent mobility control and oil washing capabilities, and could shift the wettability of rock surfaces to highly hydrophilic. In dual-core flooding experiments, with gradient differentials of 3, 5, and 7, the comprehensive oil recovery increased by 12.81 %, 13.88 %, and 11.78 %, respectively, after injecting 0.4 PV of GDCS16-4-16 surfactant solution followed by subsequent water flooding. This indicates a significant potential to enhance recovery in low-permeability tight sandstone reservoirs, presenting promising application prospects in the development of such formations.

Enhancing sand control in loose reservoirs: nanofluid application

This paper introduces a novel epoxy-based nanofluid for sand control in loose reservoirs prone to sand production issues. The nanofluid combines epoxy resin with carbon nitride nanoparticles and a gas generating agent to enhance both compressive strength and permeability. Experimental studies demonstrate significant improvements in compressive strength and permeability, indicating the potential effectiveness of the nanofluid in consolidating sand in oil and gas reservoirs. Sandpack flooding experiments under reservoir conditions reveal promising results, suggesting the nanofluid's suitability for various permeability characteristics. These findings propose the epoxy/g-C₃N₄ nanofluid as a promising solution for sand consolidation, warranting further research and field testing for practical application in reservoir engineering. Keywords: sand control; epoxy nanofluid; chemical sand consolidation; graphitic carbon nitride; compressive strength enhancement; permeability control.

Experimental Investigation on Temperature-Resistant CO2 Foam Flooding in a Heterogenous Reservoir

Gas channeling treatment is a huge challenge for oil displacement and CO2 sequestration in the practical CO2 flooding process. The foaming agents can be used in the gas flooding process, which presents good application potential for gas channeling blockage. However, high temperature can affect surfactant foaming properties. This work takes a high-temperature heterogenous sandstone oil reservoir as an example; the foaming performance of different surfactants was evaluated via foamability, thermal stability, crude oil tolerance ability, and dynamic blocking capacity. The profile control performance of the optimized foaming agent was investigated via dual-core gas flooding experiments. (1) The results show that QPJ-c featured good foaming stability, which made it present the largest foam comprehensive index, although its foaming volume was slightly lower than that of QPJ-b. Its foaming volume retention rate was 83.2%, and its half-life retention rate remained 88.9% after 30 days aging at a temperature of 110 °C. (2) The foam resistance factor increased from 7 to 17 when the core permeability increased from 2 mD to 20 mD. This indicated that the high-permeability zone could be preferentially blocked by foam during the foam injection. (3) The dual-core flooding experiments verified that the fractional flow of the high-permeability core severely decreased due to the blockage of foam. The incremental oil recovery of the low-permeability core was 27.1% when the permeability ratio was 5. It increased to 40% when the permeability ratio was increased to 10. (4) Our work indicates that temperature-resistant CO2 foam could be a good candidate for profile control during CO2 flooding in the target reservoir.

Alkali-Polymer Flooding in an Austrian Brownfield: From Laboratory to Field-Insights.

We focus on optimizing oil displacement in brownfields using alkali polymers (AP) flooding. The goal is to enhance rock-fluid and fluid-fluid interactions to improve oil recovery. The evaluation includes detailed screening of AP mixtures to ensure cost-effectiveness and maximize chemical slug efficiency, using an AP pilot project in Austria as a case study. Key aspects of the study involve assessing fluid properties to select appropriate chemical concentrations. Important parameters include the stability of produced emulsions, interfacial tension (IFT) measurements, and rheological analyses. Rock-fluid interactions were examined through core flooding experiments on both low- and high-permeability core plugs to understand fluid dynamics in heterogeneous reservoirs. A novel part of the research involved simulating the in situ aging of the AP slug, which increases its anionicity over time. Two-phase core flooding with aged chemicals provided insights into the evolution of chemical effectiveness and interactions. We found that an alkali concentration of 7500 ppm was optimal for the AP slug, particularly in its interaction with dead oil with a high total acid number (TAN), leading to emulsions with microscopic instability. Single-phase core flooding showed that the AP slug from Vendor B outperformed that from Vendor A despite mechanical stability issues. However, the additional recovery factor (RF) for polymer A-based slugs was higher in both high- and low-permeability core plugs. The findings suggest that in situ aging of the AP slug could reduce costs and enhance injection performance.

A New Self‐Healing Green Polymer Gel with Dynamic Networks for Flow Control in Harsh Reservoirs

AbstractHydrogels are widely used in flow control of underground reservoirs, a self‐healing in situ cross‐linked polymer gel system with a dynamic covalent adaptive network and dynamic disulfide bond is designed and constructed with cystine hydrochloride containing disulfide bond as a green cross‐linking agent. The polyacrylamide/cystine system can form a gel at temperatures above 110 °C, the dynamic disulfide bonds in the gel network make the hydrogels have excellent toughness and self‐healing properties and the maximum toughness value of the self‐healing gel is 57.5 MJ m−3, and the self‐healing efficiency can reach 88%. At the same time, the storage modulus of the gel can reach more than 2000 Pa with the addition of nano SiO2. The cross‐linked gel formulated using formation water is stable at 170 °C for more than 270 days. The modulated flooding experiment results show that the new gel system can effectively reduce the water content and increase the recovery rate by 32.2%. At the same time, the formation damage test shows that the average plugging rate of the gel is 95%, and the permeability damage is less than 15%. This new self‐healing green gel system can replace existing toxic gel systems and prioritize fluid flow control in harsh reservoir conditions.

Study and pilot test of in-depth conformance control based on Janus SiO2 nanoparticle emulsions-assisted inorganic gel via dual-liquid method in offshore reservoirs

Inorganic gel is one of the conformance control methods to control excess water production and extend the lifetime of oilfields. However, the inorganic gel is challenging for dual-liquid injected method and in-depth plugging performance. With the purpose of solving this issue for the application of inorganic gel in offshore oilfiled via dual-liquid method, a conformance control system based on Janus SiO2 nanoparticles (NPs) emulsion-assisted inorganic gel was proposed. In this investigation, the inorganic gel reacted with Ca2+and Mg2+ of the reservoir as ion sources, the performance of Janus SiO2 NPs and nano-emulsions was determined, and the gelation time, rheological property, and in-depth flooding performance of Janus SiO2 NPs emulsions-assisted inorganic gel system were systematically explored. The result shows that the sodium silicate concentration is determined at 0.35 wt.% based on the formation water and temperature of target reservoir. Besides, the performance of Janus SiO2 NPs is characterized by the particle size of 24 nm, which is beneficial to extend the half-life of emulsions from 7.6 h to 48 h and oil–water interfacial tension reaches 10−1∼10−2 mN/m. Also, nano-emulsions-assisted inorganic gel system can delay gelation time from 6.3 h to 29.5 h and an significant improvement in elasticity effect. Moreover, core flooding experiments were further conducted to investigate the injection capability and in-depth plugging performance. More importantly, a pilot test also provided the sufficient evidence to demonstrate the conformance control effectiveness of the Janus SiO2 NPs emulsion-assisted inorganic gel system in offshore oil field, which can be a candidate with great potentials for further field application.

Formulation of Polymer-Augmented Surfactant-Based Oil-Water Microemulsions for Application in Enhanced Oil Recovery.

This research explores the development of engineered oil-water microemulsions stabilized by a synergistic combination of polymer and surfactant to enhance stability and interfacial properties for improved enhanced oil recovery (EOR). Conventional surfactant-stabilized emulsions often suffer from phase instability and limited wettability alteration during water flooding and chemical injection, hindering the EOR efficiency. In contrast, our formulations incorporating polymers significantly increase the emulsion viscosity and resilience to temperature fluctuations, resulting in enhanced phase stability. Experimental investigations reveal that while the water-microemulsion interfacial tension (IFT) increases with salinity, the oil-microemulsion IFT decreases substantially, achieving an optimal IFT of 4.43 × 10-4 mN/m at balanced salinity levels. The microemulsions exhibit remarkable stability across varying temperatures, successfully transitioning between Winsor type II and III phases, which is critical for effective EOR applications. Notably, the addition of polymers enhances the viscosity of the surfactant-stabilized emulsion from 50 mPa·s at a shear rate of 10 s-1 to 300 mPa·s, significantly improving emulsion stability, as confirmed by measured zeta potential values of -31.1 mV for the surfactant system and -33.2 mV for the polymer-augmented surfactant system. These enhancements contribute to improved sweep efficiency during the oil recovery processes. Furthermore, the microemulsions effectively alter the sandstone wettability from oil-wet to water-wet, promoting better oil displacement. Core flooding experiments demonstrate that injecting one pore volume of the polymer-augmented surfactant-stabilized microemulsion results in an additional 20.58% oil recovery compared with conventional water flooding.

Effect of Reservoir Heterogeneity on Polymer-Surfactant Binary Chemical Flooding Efficiency in Conglomerate Reservoirs.

Reservoir heterogeneity significantly affects reservoir flooding efficiency and the formation and distribution of residual oil. As an effective method for enhancing recovery, polymer-surfactant (SP) flooding has a complex mechanism of action in inhomogeneous reservoirs. In this study, the effect of reservoir heterogeneity on the SP drive was investigated by designing core parallel flooding experiments combined with NMR and CT scanning techniques, taking conglomerate reservoirs in a Xinjiang oilfield as the research object. The experimental results show that inter-layer heterogeneity significantly affects water flooding efficiency and SP driving in low-permeability cores-the larger the permeability difference is, the more obvious the effect is-while it has almost no effect on high-permeability cores. The limited recovery enhancement in low-permeability cores is mainly due to the small percentage of contributing pores. When the permeability difference undergoes an extreme increase, the polymer molecular weight is biased towards higher values; when the polymer molecular weight is fixed, the recovery enhancement of low-permeability cores may be comparable to that of high-permeability cores when the permeability difference is extremely small. However, the recovery enhancement of the former is smaller than that of the latter when the permeability difference is extremely large. Due to intra-layer heterogeneity, there is a serious fingering phenomenon in the flooding stage, while in the SP flooding stage, recovery enhancement is most significant in the 5-20 μm pore range. This study provides an important geological basis for the rational development of a chemical flooding programme.

Enhancing Oil Recovery in Low Permeability Reservoirs through CO2 Miscible Flooding: Mechanisms and Dynamics.

Understanding the dynamic characterization of the CO2 miscible flooding process in low permeability reservoirs and its mechanism for oil recovery enhancement is crucial for controlling CO2 miscible flooding sweep efficiency and further enhancing oil recovery. This study was conducted in a low permeability reservoir in Jilin, China, using both online nuclear magnetic resonance CO2 miscible flooding and long-core CO2 miscible flooding experiments. A refined dynamic characterization of the CO2 miscible flooding process from the macroscopic core scale to the microscopic pore scale was achieved through multiple spatial online nuclear magnetic resonance testing methods. Analysis of dynamic characteristics of physical parameters was based on long-core displacement experiments and gas chromatography. This study summarizes the influence mechanism of CO2 miscible flooding on enhanced oil recovery in low permeability reservoirs and demonstrates the feasibility of CO2 miscible flooding. The results indicated that (1) CO2 miscible flooding enables simultaneous oil recovery from micro-, meso-, and macropores, significantly improving displacement efficiency. (2) The recovery process unfolds in two stages: the initial CO2 miscible flooding stage before gas breakthrough and the subsequent CO2 miscible transport stage after gas breakthrough. (3) Both stages are instrumental in expanding the macroscopic swept range of CO2, thereby enhancing oil recovery. (4) The miscibility of CO2 with crude oil can affect the oil's composition. (5) The combined effect of miscible flooding and transport underpins the high displacement efficiency of CO2 miscible flooding. Emphasizing these critical aspects could enhance oil recovery from CO2 miscible flooding in field production.

Sensitivity Analysis of Relative Permeability on Unsteady-State Core Flooding via Experimental Data

The use of computational reservoir simulation plays a key role in understanding fluid flow in geological formations, enabling the development of advanced models and accurate predictions. These simulations rely heavily on parametric constitutive relations to represent essential properties such as relative permeability (Krel), which is required for modeling continuous-scale multiphase flow in porous media. However, the majority of models described in the existing literature contain numerous empirical parameters that must be determined. Regardless of how complex their parameterization is, these parameters have no direct relationship to the problem's underlying physics. As a result, there is a need to estimate these parameters and regularly assess the associated uncertainties. Nevertheless, achieving satisfactory uncertainty quantification requires a preliminary investigation into sensitivity and linear dependence, a step that is often overlooked, especially in the context of core flood experiments. Given this issue, this study aims to analyze the reduced sensitivity coefficient of relative permeability parameters, parameterized using the LET model, in unsteady-state core flooding experiments, considering both bump and no bump conditions, while also taking into account the capillary pressure parameterized via LET. In these experiments, a plug saturated with oil undergoes axial water injection at one end, resulting in oil (and water after breakthrough) being produced at the opposite end. Experimental data includes the pressure difference between the water inlet and the oil (and water) outlet, along with the accumulated volume of produced oil. Based on experimental data, computational simulations were conducted using the Cydar® software to optimize the relative permeability and capillary pressure. The dynamic behavior of the relative permeability parameters' local sensitivity is showcased, alongside their dimensional comparison.

Hydrogen injection and withdrawal performance in depleted gas reservoirs

Residual gas trapping in porous media is a key indicator of hydrogen storage and recovery performance. The injection scheme of cushion and working gases helps maintain pressure and reduce losses. However, this information is limited in the literature. This work explores core flooding experiments (using electrical resistivity for in-situ saturation monitoring) on Bandera Grey sandstones under reservoir conditions (42 °C, 1400 psi, and 5 wt% NaCl), investigating cushion gas type and injection rate effects on storage and recovery performance. Results indicate that CO2 injection ahead of hydrogen yielded the highest storage capacity with Sgi=0.255, then CH4: Sgi=0.226 and finally, N2: Sgi=0.216. At lower injection rates (0.2–0.6 cc/min), CH4 cushion gas exhibited the highest recovery (42%), whereas at higher injection rates (1.2–10 cc/min), CO2 resulted in the highest, with 33%. These findings emphasize cushion gas's role in enhancing hydrogen storage capacity and production efficiency in depleted gas reservoirs.

Development and application of amphiphilic carbon nanotube viscosity reduction systems for enhancing oil recovery of heavy oil reservoirs

Carbon nanotubes can enhance the strength of the oil-water interface, and increase the efficiency of emulsification viscosity reduction, thus improving the recovery efficiency of heavy oil reservoirs. In this study, a type of Janus amphiphilic carbon nanotube (JCC18) was synthesized using the Pickering emulsion interfacial stabilization method. The structural characterization of JCC18 using FTIR, ESEM, and XRD confirmed the success of this synthesis. Through zeta potential, dynamic light scattering, and settlement tests, surfactant Tween 80 was identified as the optimal dispersant for JCC18. Emulsification tests demonstrated that the nanofluid emulsified water with crude oil to form an oil-in-water emulsion, and it achieved a maximum viscosity reduction rate of over 99.9% (±0.99%). The viscosity reduction rate of crude oil increased with the water-to-oil volume ratio, nanoparticle concentration, or temperature. However, an increase in the mineralization level decreased the reduction rate of oil viscosity. Compared to the systems without nanoparticles, the nanofluid demonstrated superior performance in reducing crude oil viscosity both before and after aging. Furthermore, the interfacial tension between the nanofluid and crude oil was lowest, reaching 0.153 (±0.002) mN/m. The interfacial tension was more pronounced with the increase in temperature. As the mineralization level increased, the interfacial tension between the nanofluid and crude oil initially decreased and then increased. The core flooding experiments showed that compared to the primary water flooding, the nanofluid, and secondary water flooding enhanced the recovery by 21.92% (±0.22%). These results validated the significant potential of the amphiphilic carbon nanotube fluid in enhancing heavy oil recovery.

Experimental investigation and predictive modeling of dry-out and salt precipitation effects during underground gas storage operations

Formation damage poses the greatest threat to underground gas storage (UGS) operations, with permeability reduction being a key cause of injectivity and productivity losses. To better understand the mechanisms behind dry-out and salt precipitation (DSP) and predict the resulting near-wellbore damage, this study experimentally and quantitatively evaluates key factors affecting rock properties before and after salt precipitation. We conducted long-term gas-brine core flooding experiments, obtained salt-contaminated samples, and supplemented them with core permeability-porosity parameter tests, high-pressure mercury intrusion porosimetry (MIP), and scanning electron microscopy (SEM) experiments to better evaluate the salt clogging behavior of the samples. In addition, we discussed the applicability of the key parameter prediction model in modeling the DSP effects, including the water content of natural gas (WCNG), the porosity-permeability clogging model (PPC), and relative permeability (RP) function, providing usage recommendations. Based on our findings, we introduced a model to predict water saturation, salt saturation, and the salt-induced skin factor near the wellbore, particularly after viscous displacement ends, when liquid becomes immobile and evaporation dominates.The results show that salt precipitation has a significant impact on core porosity and permeability. Notably, lower flow rates subtly promote salt precipitation by enhancing the role of evaporation, resulting in greater salt accumulation. In addition, elevated salinity and higher initial water saturation are key contributors to the precipitation process, further exacerbating salt buildup within the reservoir. MIP experiments further confirm the aforementioned impacts. SEM observations reveal NaCl crystals, either clustered or isolated, extensively distributed within the pores and filling the pore spaces from micro to nanometer scale, highlighting their substantial role in altering pore structure and impacting porosity and permeability due to DSP effects. Our developed model confirms that high temperature, low pressure, high flow rates, low initial porosity and permeability, and strong near-well inertia effects lead to DSP effects manifesting sooner near the wellbore during the post-viscous displacement stage. Model validation with core-scale predictions closely matches experimental data in terms of trend.By laying the groundwork for analyzing the mechanisms of flow-through drying and salt precipitation, our findings can be directly applied to identifying the key controlling factors influencing DSP effects, mitigating formation damage, improving injectivity and productivity, and enhancing the efficiency of UGS operations under various operational conditions.

Permeability shifts in chalk core during produced water reinjection

Chalk reservoirs, due to their high porosity and very low permeability, represent one of the most interesting cases for engineering studies of carbonates. They exhibit complex fluid-rock interactions because of their reactive surfaces and dense porous medium. The reinjection of produced water is an attractive strategy for managing wastewater flow from oil wells. However, the complex composition of produced water, the reactive nature of carbonate rocks, and their low permeability create challenges related to permeability loss.This study examines the stages of permeability change during core flooding experiments up to the point of complete clogging. A distinctive feature of this study is the presence of residual oil in the core samples, which simulates real reservoir conditions during produced water reinjection. The presence of residual oil is an additional factor influencing the change in core permeability, but there is no clear consensus in the research community on its impact on permeability during produced water injection.All experiments were conducted in a core flooding system simulating well conditions in terms of pressure (170 bar) and temperature (70 °C). Produced water samples from the Dan field were used to replicate the chemical and thermodynamic processes occurring in a real well. The experiments identified three stages of permeability change: an initial increase in permeability (+12%), a period of pressure stabilization, and a subsequent decrease in permeability (−8%) due to the formation of inorganic precipitates within the core channels.The primary objective of the experiments is to investigate the relationship between permeability changes and the stages of reinjection, with a focus on the effects of residual oil. The study focuses on identifying the processes occurring up to the point of complete clogging, considering the impact of residual oil saturation in the chalk core samples. Image analysis using scanning electron microscopy, particle size measurement with a zeta-potential meter, and thermodynamic scale formation modeling with ScaleCERE software were employed to explain these processes.Three stages of permeability change were identified during the injection of 200 pore volumes of produced water: increased permeability (+12%), pressure stabilization, and decreased permeability (−8%). The positive influence of residual oil saturation on the filtration and storage properties of the reservoir was established, due to the mobilization of chalk core particles. Additionally, the theory of core channel clogging during the reinjection of formation water by the formation of inorganic precipitates within the channels was confirmed.Understanding the causes of permeability reduction that occurred during the stage of permeability decrease enables the development of water purification methods specifically targeted at the causes of rock clogging. Predicting the process of injecting a mixture of produced and seawater will help in interpreting the data during disposal operations by injecting formation water into an injection well, and it will allow for the selection of effective measures to mitigate the impact on the reservoir.

Self-regulating profile control strategy for CO2 flooding by the phase-transition acid

To solve the problem of low sweep efficiency caused by gas channeling in CO2 flooding, the CO2 stimulated response liquid–solid transition system (TA-D230) was designed by the tetradecanedioic acid (TA) and poly(propylene glycol) bis(2-aminopropylether) (D230). TA, which has high melting point and is insoluble in water, achieves the transition from solid phase to liquid phase by the self-assembly method with D230. After CO2 injection, the TA was precipitated from TA-D230 solution as the solid. The transformation mechanism from TA-D230 to TA was confirmed by 1H NMR and FTIR due to the reduction of COO− group to COOH group. The TA exhibited a high melting point of 128 °C by the DSC, which can be applied in high temperature reservoirs. In addition, by recording the changes in conductivity and pH during the injection of CO2, 0.1 mol/L TA-D230 achieved rapid precipitation within 5 min and in a 5000 ppm NaCl solution. The core flooding experiment further assessed that TA-D230 has excellent ability to enhance oil recovery with a value of 15.3 %. This method provides a new perspective and solution for profile control in oil and gas development.

Evaluation of the Compatibility Between Formation and Injection Water in Ultra-Low Permeability Reservoirs

This study focuses on the reservoir scaling and the under-injection issues of the water injection well during the water injection development of an ultra-low permeability reservoir in Xinjiang due to the complex composition of injected water. Microfluidic experiments were applied to visualize the flow channel changes during water flooding, indoor core flooding experiments were employed to analyze the permeability and ion concentration, and nuclear magnetic resonance (NMR) was used to evaluate the pore structure damage. Together, these experiments were used to clarify the scaling and precipitation characteristics as the injected water met the formation water in porous media and the effects on reservoir damage. The research results showed that the poor compatibility of the injected water with the formation water could easily produce calcium carbonate scaling. The scaling products exhibited a unique network structure of blocks and a radial distribution, mainly composed of calcium carbonate and aluminosilicate. The scaling in the porous media exhibited the characteristics of unstable crystal precipitation, migration, and repeated scaling following water mixing, while the scale crystal growth occurred in the pores and the throats. According to the scaling characteristics, the damage to the reservoir permeability by scaling can be divided into the induction, damage, and stabilization stages. The filling and clogging of the scale crystals enhanced the pore structure heterogeneity, with the median pore radius reduced by 21.61% and the permeability reduced by 50%.

Measurement of Acrylamido Tertiary Butyl Sulfonate Polymer Retention on Limestone by Three Methods Under Varying Temperature and Oil Presence

Summary Polymer retention poses a significant challenge in polymer flooding applications, emphasizing the importance of accurately determining retention levels for successful project design. In carbonate reservoirs of the Middle East, where temperatures exceed 90°C, conducting adsorption tests under similar temperature conditions becomes crucial for the precise determination of adsorption values. The choice of analytical method potentially impacts the accuracy of retention measurements from effluent analysis. This study investigates the effect of temperature on the performance of a polymer, specifically its rheological behavior and retention. Rheological and polymer flooding experiments were carried out using an acrylamido tertiary butyl sulfonate (ATBS)-based polymer in formation water (167,114 ppm) at different temperatures (25°C, 60°C, and 90°C) with required oxygen control measures. Dynamic polymer retention was conducted in both the absence of oil (single-phase tests) and the presence of oil (two-phase tests). In addition, different analytical techniques were evaluated, including viscosity measurements, ultraviolet (UV)-visible spectroscopy, and total organic carbon-total nitrogen (TOC-TN) analysis, to determine the most accurate method for measuring the polymer concentration with the least associated uncertainty. Furthermore, the study investigates the effects of these uncertainties on the final dynamic polymer retention values by applying the propagation of error theory. The effluent polymer concentration was determined using viscosity correlation, UV spectrometry, and TOC-TN analysis, all of which were reliable methods with coefficient of determination (R2) values of ~0.99. The study analyzed the effects of flow through porous media and backpressure regulator on polymer degradation. The results showed that the degradation rates were around 2% for flow through porous media and 16% for mechanical degradation due to the backpressure regulator for all temperature conditions. For the effluent sample, the concentration of polymer was lower when using the viscosity method due to polymer degradation. However, the TOC-TN and UV methods were unaffected as they measured the TN and absorbance at a specific wavelength, respectively. Therefore, all viscosity results were corrected for polymer degradation effects in all tests. During the two-phase coreflooding experiment conducted at 25°C, the accuracy of the UV spectrometry and viscosity measurements was affected by the presence of oil, rendering these methods unsuitable. However, the TOC-TN measurements were able to determine effluent polymer concentration and, subsequently, the retention value. Moreover, the use of glycerin preflush to inhibit oil production during polymer injection in the two-phase studies showed that all three methods were appropriate. The error range was obtained using the propagation of error theory for all the methods. Accordingly, it was noted that the temperature did not affect the dynamic retention values in both single-phase and two-phase conditions. The findings of this study highlight that when adequate oxygen control measures are implemented, the temperature does not exhibit a statistically significant impact on the retention of the ATBS-based polymer under investigation. Furthermore, TOC-TN has been identified as the optimal analytical method due to its minimal uncertainties and ease of measuring polymer concentration under varying experimental conditions.