Influence of Heterogeneity on Nitrogen Foam Flooding in Low-Permeability Light Oil Reservoirs

Wang, Mengyu; Yang, Shenglai; Li, Meng; Wang, Shuang; Peng, Yu; Zhang, Yuxiang; Chen, Hao

doi:10.1021/acs.energyfuels.0c04062

Cited by 19 publications

(6 citation statements)

References 59 publications

(82 reference statements)

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“…Gas flooding for enhanced oil recovery (EOR) has received extensive attention due to its high oil displacement efficiency, good injectivity, and low cost in many scenarios (Dehdari et al, 2020; Eftekhari et al, 2015; Farajzadeh et al, 2009; X. Wang & Mohanty, 2021). As an efficient and environmentally friendly EOR method, gas flooding has some obvious technical advantages over water flooding and is especially suitable for low‐permeability oil reservoirs (M. Wang et al, 2021; Wei, Pu, Sun, Pu, et al, 2018). The most available gas sources used for EOR include CO 2 , natural gas, N 2 , and air (Hurtado et al, 2018; Janssen et al, 2018; Khalaf & Mansoori, 2019; Lang et al, 2020; Liao et al, 2018; Liu et al, 2017; Luo et al, 2017).…”

Section: Introductionmentioning

confidence: 99%

Stabilization of natural gas foams using different surfactants at high pressure and high temperature conditions

Bi¹,

Zhang

et al. 2021

J Surfact & Detergents

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Natural gas foam can be used for mobility control and channel blocking during natural gas injection for enhanced oil recovery, in which stable foams need to be used at high reservoir temperature, high pressure and high water salinity conditions in field applications. In this study, the performance of methane (CH 4 ) foams stabilized by different types of surfactants was tested using a high pressure and high temperature foam meter for surfactant screening and selection, including anionic surfactant (sodium dodecyl sulfate), non-anionic surfactant (alkyl polyglycoside), zwitterionic surfactant (dodecyl dimethyl betaine) and cationic surfactant (dodecyl trimethyl ammonium chloride), and the results show that CH 4 -SDS foam has much better performance than that of the other three surfactants. The influences of gas types (CH 4 , N 2 , and CO 2 ), surfactant concentration, temperature (up to 110 C), pressure (up to 12.0 MPa), and the presence of polymers as foam stabilizer on foam performance was also evaluated using SDS surfactant. The experimental results show that the stability of CH 4 foam is better than that of CO 2 foam, while N 2 foam is the most stable, and CO 2 foam has the largest foam volume, which can be attributed to the strong interactions between CO 2 molecules with H 2 O. The foaming ability and foam stability increase with the increase of the SDS concentration up to 1.0 wt% (0.035 mol/L), but a further increase of the surfactant concentration has a negative effect. The high temperature can greatly reduce the stability of CH 4 -SDS foam, while the foaming ability and foam stability can be significantly enhanced at high pressure. The addition of a small amount of polyacrylamide as a foam stabilizer can significantly increase the viscosity of the bulk solution and improve the foam stability, and the higher the molecular weight of the polymer, the higher viscosity of the foam liquid film, the better foam performance.

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Section: Introductionmentioning

confidence: 99%

Stabilization of natural gas foams using different surfactants at high pressure and high temperature conditions

Bi¹,

Zhang

et al. 2021

J Surfact & Detergents

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“…However, the low oil and gas output is far from meeting domestic demand in China [1]. The development of conventional high and intermediate permeability reservoirs has entered into high water cut stage, and the development of ultra-low permeability reservoirs has gradually become a key focus in the oilfield [2]. The biggest characteristic of ultra-low permeability reservoirs is poor physical property, small pore-throat structure, high flow resistance, and fast decline in single-well production, which brings great challenges [3].…”

Section: Introductionmentioning

confidence: 99%

Integrated CO2 Miscible Flooding-Storage Technologies for Complex Fault Block Reservoirs with Low Permeability

Yu¹,

Sun²,

Tang³

et al. 2023

Preprint

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During the production process of complex fault block reservoirs with low permeability, the systematic research on the combination of oil displacement and storage is fuzzy. This work aims at oil displacement and storage to supplement formation energy and evaluate storage potential. Firstly, the optimal development scheme is designed by layer division and miscible and ability. Secondly, based on large amounts of field data, the novel FAHP evaluation system for CO2 storage site selection is established. Thirdly, since judging adaptability evaluation is suitable, the carbon storage simulation is conducted to contain mineralization, dissolved and structural mechanisms. The results indicate that after 1.2HCPV CO 2 injected cumulatively into reservoir, the cumulative oil increase reached 4001.80×10 4 m 3 and the final recovery rate was 44.46%, achieving a good effect. At the stage of injection, the CO2 capacity remaining in the reservoir was nearly 1657.53×10 4 t and the gas storage rate reached 43.84%. The novel evaluation system for CO 2 storage site selection shows that the target reservoir has more storage space, large injection capacity, high safety factor and low storage cost, which is allowed to storage. At the stage of storage, the effective storage capacity of target reservoir was 2257.48×10 4 t, of which the structural storage capacity was 73.43% and the mineral storage capacity was the least (3.46%). The average annual CO 2 storage capacity is about 225.74×10 4 t, which is equivalent to planting 2031.69×10 4 t trees or shutting down 135.69×10 4 cars for one year, achieving oil displacement/storage synergetic optimization. The findings of this study can offer engineers guidance for ensuring the long-term, stable and safe operation of CO 2 storage. For complex fault block reservoirs with low permeability "green, low-carbon, efficient" development has a certain reference.

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“…Low and ultra-low permeability light oil reservoirs have tiny pore throats, and water flooding development has long faced major problems such as the failure to inject and recover [ 1 , 2 ]. The air flooding technique has obvious advantages such as easy injection, sufficient gas sources, and environmental protection [ 3 , 4 ].…”

Section: Introductionmentioning

confidence: 99%

Identification of Gas Channeling and Construction of a Gel-Enhanced Foam Plugging System for Oxygen-Reduced Air Flooding in the Changqing Oilfield

Wang

Qin

et al. 2022

Gels

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The accurate identification of gas channeling channels during foam-assisted oxygen-reduced air flooding (FAORAF) and the analysis of the main controlling factors are essential to propose reasonable and effective countermeasures to enhance oil recovery (EOR). However, there are few comprehensive studies on identifying gas channeling channels, the influencing factors, and the corresponding plugging EOR systems in FAORAF. The channeling channels of the injection and production wells of the Changqing Oilfield, China, under varying development schemes are identified utilizing fuzzy membership function theory in this work to obtain their primary distribution. The characteristics and influence factors of gas channeling channels are analyzed by numerical simulation using CMG. The recovery performance of each foam blocking system is evaluated by twin-tube sand pack models. As well, based on the features of reservoir fractures, a new gel-enhanced foam plugging system is developed. The results show that channeling channels chiefly develop along NE 60–70° and that foam could reduce gas channeling. Natural and artificial fractures are the principal factors causing gas channeling, followed by the injection method and gas injection rate. Under the premise of the injection and migration efficiency, the optimal gel system is a 0.1% HPAM + 0.1% organic chromium crosslinking agent. The addition of gel increases the viscosity of the liquid phase and strengthens the mechanical strength of the foam liquid film. At a permeability ratio of 12, the recovery factors of the binary plugging systems composed of microspheres, PEG, and gel combined with foam are 40.89%, 45.85%, and 53.33%, respectively. The movable gel foam system has a short breaking time (only 18 days) and a recovery factor of about 40% at a permeability ratio of 20. To be suitable for oil reservoirs with microfractures, an improved ternary gel foam system—0.1% HPAM + 0.1% chromium crosslinking agent + 0.05–0.1% nano-SiO2—is developed. Compared with the binary gel foam system, the recovery rate of the new nano-SiO2 gel foam system after 15 days of ageing using the core splitting test is 25.24% during the FAORAF process, increasing by 12.38%.

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Influence of Heterogeneity on Nitrogen Foam Flooding in Low-Permeability Light Oil Reservoirs

Cited by 19 publications

References 59 publications

Stabilization of natural gas foams using different surfactants at high pressure and high temperature conditions

Stabilization of natural gas foams using different surfactants at high pressure and high temperature conditions

Integrated CO2 Miscible Flooding-Storage Technologies for Complex Fault Block Reservoirs with Low Permeability

Identification of Gas Channeling and Construction of a Gel-Enhanced Foam Plugging System for Oxygen-Reduced Air Flooding in the Changqing Oilfield

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