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Du D.,China University of Petroleum - East China | Li D.,China University of Petroleum - East China | Shi D.,Shengli Oilfield Branch Company | Xu T.,The Third Mine of Hekou Oil Production Factory
Jisuan Wuli/Chinese Journal of Computational Physics | Year: 2011

Nine kinds of heavy oil thermal recovery models are summarized, including non-Newtonian power-law fiuids model, two-region composite reservoir model, three-region composite reservoir model, multi-region composite reservoir model, model with consideration of gravity override and interference testing well model, etc. Pressures and pressure derivatives are briefly analyzed. Advantages and disadvantages of models are compared. Problems in current models and trends in research of heavy oil well test are pointed out.

Qiu Z.,Chongqing University of Science and Technology | Qiu K.,Chongqing University of Science and Technology | Wang Z.,Shengli Oilfield Branch Company
Applied Mechanics and Materials | Year: 2012

In order to put forward the Anti-scale measures of shaft in Shunan Gas Mine and guarantee the normal production of gas field, the composition as well as the water quality and scaling type for gas production water at the typical shaft mouth of Shunan Gas Mine are analyzed and the scaling mechanism of shaft and the influencing factors are described as well as the anti-scale agent and the solid anti-scale blocks pertaining to the scaling of shaft in Shunan Gas Mine are obtained.

Yao T.-Y.,China University of Petroleum - East China | Li J.-S.,Shengli Oilfield Branch Company
Oilfield Chemistry | Year: 2010

In this experimental study conducted at 651, three aqueous surfactant solutions (ASSs) were used; 0.01% RS-2, a quarternary ammonium salt surfactant; 0. 05% RS-2+0.5%Na2CO3 ; and 0.05%RS-2 +0.5%NaOH. The interfacial tension between these ASSs and Gudao heavy crude oil(HCO) was of magnititude 10°, 10-1, and 10-2 mN/m, respectively. The water separation in 60 min from the emulsions formed by mixing the ASSs and the HCO in equal volume ratio, demonstrating the emulsion stability, was of 67.0% ,12.5% , and 8. 0% and the droplet size in the emulsions was of 18, 15, and 3 pjn in average, respectively. In ASS flooding experiments on sand packs the highest enhancement in oil recovery from homogeneous sand packs was observed with 0.05% RS-2 + 0.5%NaOH solution(1 PV) injected, reaching 22.3% after 25.4% oil recovered by water flood, and from heterogeneous sand packs - with 0.05% RS-2 + 0.5% Na2CO3 solution(1 PV) injected, being of 18.0% after 16.0% oil recovered by water flood, and in the later case the injecting pressure was higher and kept at a higher level in longer time duration. It was considered that a chemical flooding solution was more effective in heterogeneous heavy oil reservoirs when it could create more stable emulsions with droplets slightly larger in size than the pore size in highly permeable zones and the chemical flooding system screened through heterogeneous physical model flooding tests might be more suitable for the real reservoir.

Liu L.-B.,Shengli Oilfield Branch Company | Dai C.-L.,China University of Petroleum - East China | Dai C.-L.,China University of Petroleum - Beijing | Zhao J.,China University of Petroleum - East China | And 3 more authors.
Oilfield Chemistry | Year: 2010

Complex chromium gels have the broad prospect and potential important applications in the deep water shutoff, profile control and oil displacement. Chromium gel researched in this paper was prepared by the crosslinking reaction of the HPAM and complex chromium ions, obtained by compounding chromium acetate with chromium lactate. The influence of the various factors, such as HPAM mass fraction(0.1%-0.4%), crosslinker mass fraction(0.1%-0.4%), pH value(5 -8) and temperature(40-80°C), on gelation time (determined through viscosimetry and strength code method) and gel strength (determined through breakthrough vacuum method) of the HPAM-complex chromium gel were evaluated. The results showed that with the increase of polymer mass fraction, crosslinking mass fraction and temperature, gelation time(including initial gelation time and final gelation time) got shorter and BV increased, at the same time, when the temperature is more than 60°C, the gelation time was greatly reduced. pH value had little effect on gel strength, when pH =7.0, the gelation time was the shortest; while the gelation time got longer under weak acid or weak alkaline conditions. The gelation time and gel strength of complex chromium gel followed the law of the conventional gel, that is, the shorter the gelation time, the greater the gel strength.

Yao T.-Y.,China University of Petroleum - East China | Li J.-S.,Shengli Oilfield Branch Company | Huang Y.-Z.,CAS Institute of Porous Flow and Fluid Mechanics
Shenzhen Daxue Xuebao (Ligong Ban)/Journal of Shenzhen University Science and Engineering | Year: 2012

Effects and mechanisms of temperature and stress on permeability and porosity of low permeability reservoir were studied by large-scale high-temperature high-pressure permeability instrument, nuclear magnetic resonance testing, rate-controlled mercury penetration technique and relative permeability testing. The results show that when temperature is constant, the permeability of sandstone decreases with the increase of stress while, when stress is constant, the permeability of sandstone decreases with the increase of temperature. The results of nuclear magnetic resonance testing and rate-controlled mercury penetration experiments show that when stress increases, framework grains arranged more densely, and the average radius of pore throat and main pore throat decreases, resulting in worse connectivity, fewer accessible pores and an increase in bound water saturation.

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