New method for plugging channeling in oil field by nitrogen foam

Yang, Zhaopeng; Gao, Shusheng; Yue, Xiang-an; Lu, Yugang; Sui, Hong-gang; Wei, Haoguang

doi:10.1007/s11771-014-1988-2

Cited by 3 publications

(2 citation statements)

References 1 publication

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Using associated polymers such as AP-P4, researchers have managed to develop temperature-and salt-resistant gels that are stable at 95 • C and 16.0 × 10 4 mg/L [6][7][8][9]. In contrast, cationic polymers are positively charged and therefore tend to exclude other cations in water (especially Ca 2+ /Mg 2+ ions).…”

Section: Introductionmentioning

confidence: 99%

Optimization of the Methods to Develop Stable Polymer Gels for Water Management in Medium- and Ultra-High-Salinity Reservoirs

Ding

et al. 2023

Gels

View full text Add to dashboard Cite

Polymer gels suffer from a serious syneresis issue when exposed to high-temperature and high-salinity (HTHS) conditions, which limits their use as water-treatment agents in this type of reservoir. In this paper, the effects of the polymer type/concentration, deoxidizers, and stabilizers on the long-term stability of polymer gels were systematically studied; thus, the methods to develop stable polymer gels for two typical levels of salinity were optimized. The results show the following: (1) For a medium-salinity condition (TDS: 33,645.0 mg/L) at 125 °C, conventional HPAM gels completely dehydrate within only 1 day, and the addition of a deoxidizer hardly improved their stability. Some special polymers, e.g., AP-P5, MKY, and CPAM, are able to form stable gels if a high concentration of 0.8% is used; the syneresis rate of these gels is about 10% after 30 days. However, the addition of the complexant sodium oxalate significantly improves the stability of gels formed by all five of these different polymers, which behave with a 0% syneresis rate after 30 days pass. Complexants are the most economical and feasible agents to develop stable gels in medium-salinity water. (2) Gels enhanced using the methods above all become unstable in a more challenging ultra-high-saline condition (TDS: 225,068.0 mg/L). In this case, special calcium- and magnesium-resistant polymers are required to prepare stable gels, which show 0% syneresis rates after 30 days, have relatively low strengths, but do produce a good plugging effect in high-permeability cores.

show abstract

Section: Introductionmentioning

confidence: 99%

Optimization of the Methods to Develop Stable Polymer Gels for Water Management in Medium- and Ultra-High-Salinity Reservoirs

Ding

et al. 2023

Gels

View full text Add to dashboard Cite

show abstract

“…And the plugging gel system has been optimized in the aspect of determination of optimum gelling time and the key factors of its application [9,10] . In order to block high permeable portions, studies of the N2 or CO2 foam flooding were carried out [11,12] . At the same time, water shutoff and conformance systems such as organic chromium polymer gel, precross-link particles and modified phenolic resin, are appropriate for medium and high permeability reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Evaluation and Optimization of Conformance Control by Modified Starch Gel in Low Permeability Cores with Fracture

Zhao¹,

Wang²,

Hou³

et al. 2017

dtetr

View full text Add to dashboard Cite

The artificial or natural fracture network in low permeability reservoirs provide drainage passages for the oil, but cause severe channeling during the water flooding. The best solution is to inject water shutoff agent to plug the water channels and enhance sweeping volume by bypassed water. This study introduces a new formula of conformance control agent -modified starch gel system, and experiments are conducted to evaluate its physical properties, optimal injection volume as conformance modifier, and its performance in fractured cores of low permeability. Experiments shows that the gel has high elasticity, strength and toughness in gel form, and can be injected into the fractured core under low differential pressure in solution form. The gel slug is strong enough to seal the fracture and resist washout after gel placement. Core flooding experiments indicate that the pressure gradient of gel displacement in the fracture is enough to divert the subsequent water to sweep the matrix, enhancing sweeping volume of water.

show abstract

Remaining oil distribution in models with different heterogeneities after CO2 WAG injection: Visual research by nuclear magnetic resonance technique

Wang

Zhang

et al. 2021

J. Cent. South Univ.

View full text Add to dashboard Cite

New method for plugging channeling in oil field by nitrogen foam

Cited by 3 publications

References 1 publication

Optimization of the Methods to Develop Stable Polymer Gels for Water Management in Medium- and Ultra-High-Salinity Reservoirs

Optimization of the Methods to Develop Stable Polymer Gels for Water Management in Medium- and Ultra-High-Salinity Reservoirs

Evaluation and Optimization of Conformance Control by Modified Starch Gel in Low Permeability Cores with Fracture

Remaining oil distribution in models with different heterogeneities after CO2 WAG injection: Visual research by nuclear magnetic resonance technique

Contact Info

Product

Resources

About