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Li S.,Petrochina | Duan X.,China University of Petroleum - Beijing | Duan X.,Key Laboratory of Petroleum Engineering | Hou J.,China University of Petroleum - Beijing | And 5 more authors.
Shiyou Huagong Gaodeng Xuexiao Xuebao/Journal of Petrochemical Universities | Year: 2014

The appropriate HLB of emulsifier was screened and evaluated, and emulsion with strong stability was selected. Static test results showed that emulsion had good resistance and salt resistance. With the increasing salinity, stable performance of the emulsion decreased slightly. The flow resistance can be improved 140 times when the liquid viscosity was high, illustrating that the emulsion system had the good displacement effect in high temperature and salinity conditions. Displacement experiments show that the matching of emulsion drops with pore throat decides transport of emulsion liquid in porous media capabilities.


Duan X.,China University of Petroleum - Beijing | Duan X.,China National Petroleum Corporation | Duan X.,Key Laboratory of Petroleum Engineering | Hou J.,China University of Petroleum - Beijing | And 7 more authors.
Shiyou Huagong/Petrochemical Technology | Year: 2013

Great advances have been made in foam flooding technique for the improvement of oil recovery. The research progresses in foaming agents with oil resistant stability in recent years were reviewed. The defoaming property of foam in the presence of oil and the oil resistant mechanism of the foaming agents were discussed according to the molecular structure and surface/interfacial tension of the surfactants. The superiority and limitations of several oil resistant foaming agents were analyzed. Supercritical CO2 foam and fluorocarbon surfactant foam have considerable oil resistance, but their oil resistant mechanism and application should further be studied. The main directions for the research of the future oil resistant foaming agents are effectively mixing the surfactant systems and adding proper additives.


Xue Y.,Key Laboratory of Petroleum Engineering | Cheng L.,Key Laboratory of Petroleum Engineering | Li C.,Key Laboratory of Petroleum Engineering
Advanced Materials Research | Year: 2012

Whether the stress sensitivity in the mid-high permeability is stronger than that in the low permeability reservoir is current hot debate, aimed at this question. 14 samples are selected to calculate the permeability loss rate separately in the laboratory simulation experiment, the results show that the absolute value of loss rate of the mid-high permeability core is higher than that of low permeability core, but the relative permeability loss rate is lower than that of low permeability core, which, namely, means the low-permeability reservoir has stronger stress sensitivity. The stress sensitivity curve in the high permeability reservoirs could be classified into the type model of "gentle", while the stress sensitivity curve in the low permeability reservoir could be concluded as the "first steep then slow " mode. Hence the bottom-hole flowing pressure must be controlled reasonably in order to keep the productivity well. © (2012) Trans Tech Publications, Switzerland.


Li Z.,China University of Petroleum - Beijing | Li Z.,China National Petroleum Corporation | Li Z.,Key Laboratory of Petroleum Engineering | Zhang W.,China HuaYou Group Corporation | And 10 more authors.
Journal of Natural Gas Science and Engineering | Year: 2016

Alkaline-Surfactant-Polymer (ASP) flooding is an emerging chemical Enhanced Oil Recovery (EOR) technology which has significantly enhanced oil recovery of Daqing Oilfield. ASP flooding benefits from the synergy effects of alkali, surfactant and polymer to improve both volumetric and displacement efficiencies and meanwhile lower surfactant adsorption. However, ASP flooding also induces some negative formation damage effects such as scaling, adsorption, and mineral dissolution. In this paper, we investigated the formation damage caused during ASP flooding in Block Sanan-5 in Songliao Basin – one of the most productive blocks of Daqing Oilfield in China. It was found that the distribution of formation damage caused by ASP flooding followed flow paths of chemical solutions and was dependent on well locations. The severity of damage varies as distance increases from the near-injection-well area to the near-production-well area. Understanding the effects of well locations on formation damage during ASP flooding could provide more accurate evaluation of formation damage and helped to guide reservoir development strategies. To analyze the well location factor, we collected scaling samples and more than 970 m of core samples from Block Sanan-5 of Daqing Oilfield covering different wells on various flow paths before and after ASP flooding. The changes of some key petrophysical parameters such as porosity and permeability before and after ASP flooding were investigated. A series of experiments, including Scanning Electron Microscopy (SEM), Casting Thin Sections (CTS), X-Ray Diffraction (XRD) and ion analysis of produced water were performed to test properties of core samples. In addition, absorption of different components in the ASP solutions was also measured. Experimental results indicate that the ASP flooding has considerably different influences on different parts of flow paths. After ASP flooding, permeability distribution of core samples exhibits different variability trends from the near-injection-well areas to near-production-well areas. Due to absorption of alkali and polymer, grains migration and scaling of calcium and magnesium, permeability decreases at the near-injection-well area, then increases at an intermediate distance and decreases again at the near-production-well. Moreover, porosity of samples shows a similar tendency with variability of permeability, which is interpreted by the strong mineral corrosion due to high concentration of alkali in the near-wellbore area, while its extent of variation is smaller than permeability. © 2016 Elsevier B.V.


Duan X.,China University of Petroleum - Beijing | Duan X.,China National Petroleum Corporation | Duan X.,Key Laboratory of Petroleum Engineering | Hou J.,China University of Petroleum - Beijing | And 11 more authors.
Journal of the Energy Institute | Year: 2016

In order to study the effect of gas channel on CO2 flooding in porous medium, the gas flow velocity is divided into two parts: gas breakthrough stage and gas channeling stage. The breakthrough velocity has an exponential relationship with concentration in the frontal zone of gas area, while the channeling velocity has a linear relationship with injection pressure drop. A new method is proposed to determine the gas channeling time by using the trend line of gas-oil ratio in gas breakthrough and gas channeling stage. The production characteristics in CO2 flooding show that recovery greatly improves after the gas breakthrough at the outlet of core sample, and most of the oil displaces before gas channeling. Thus, the extension of the stage between gas breakthrough and gas channeling becomes a key factor to improve CO2 recovery efficiency. Improving the injection pressure drop increases the dissolved gas diffusion, which will improve the oil displacement efficiency of simultaneous oil and gas production stage, but it also increases gas channeling velocity, which will increase the gas/oil ratio sharply and result in ineffective gas injection. An optimal displacement pressure can control the diffusion rate, the channeling rate and improve the recovery of CO2 flooding effectively. Keeping a constant pressure drop, increasing of injection pressure can not only increase the diffusion rate, but also reduce the gas channeling velocity. The achievement of a lower gas channeling velocity is advisable for extending the stage of gas-liquid production, and improving the immiscible CO2 recovery significantly. © 2015 Energy Institute. Published by Elsevier Ltd. All rights reserved.


Hou J.-R.,China University of Petroleum - Beijing | Hou J.-R.,Sinopec | Hou J.-R.,Key Laboratory of Petroleum Engineering | Zheng Z.-Y.,China University of Petroleum - Beijing | And 17 more authors.
Petroleum Science | Year: 2016

With complex fractured-vuggy heterogeneous structures, water has to be injected to facilitate oil production. However, the effect of different water injection modes on oil recovery varies. The limitation of existing numerical simulation methods in representing fractured-vuggy carbonate reservoirs makes numerical simulation difficult to characterize the fluid flow in these reservoirs. In this paper, based on a geological example unit in the Tahe Oilfield, a three-dimensional physical model was designed and constructed to simulate fluid flow in a fractured-vuggy reservoir according to similarity criteria. The model was validated by simulating a bottom water drive reservoir, and then subsequent water injection modes were optimized. These were continuous (constant rate), intermittent, and pulsed injection of water. Experimental results reveal that due to the unbalanced formation pressure caused by pulsed water injection, the swept volume was expanded and consequently the highest oil recovery increment was achieved. Similar to continuous water injection, intermittent injection was influenced by factors including the connectivity of the fractured-vuggy reservoir, well depth, and the injection–production relationship, which led to a relative low oil recovery. This study may provide a constructive guide to field production and for the development of the commercial numerical models specialized for fractured-vuggy carbonate reservoirs. © 2016 The Author(s)


Zhao F.,China University of Petroleum - Beijing | Zhao F.,China National Petroleum Corporation | Zhao F.,Key Laboratory of Petroleum Engineering | Zhang L.,China University of Petroleum - Beijing | And 8 more authors.
Petroleum Science | Year: 2014

Gas flooding such as CO2 flooding may be effectively applied to ultra-low permeability reservoirs, but gas channeling is inevitable due to low viscosity and high mobility of gas and formation heterogeneity. In order to mitigate or prevent gas channeling, ethylenediamine is chosen for permeability profile control. The reaction mechanism of ethylenediamine with CO2, injection performance, swept volume, and enhanced oil recovery were systematically evaluated. The reaction product of ethylenediamine and CO2 was a white solid or a light yellow viscous liquid, which would mitigate or prevent gas channeling. Also, ethylenediamine could be easily injected into ultra-low permeability cores at high temperature with protective ethanol slugs. The core was swept by injection of 0.3 PV ethylenediamine. Oil displacement tests performed on heterogeneous models with closed fractures, oil recovery was significantly enhanced with injection of ethylenediamine. Experimental results showed that using ethylenediamine to plug high permeability layers would provide a new research idea for the gas injection in fractured, heterogeneous and ultra-low permeability reservoirs. This technology has the potential to be widely applied in oilfields. © 2014 China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg.


Wang F.-G.,China University of Petroleum - Beijing | Wang F.-G.,China National Petroleum Corporation | Wang F.-G.,Key Laboratory of Petroleum Engineering | Hou J.-R.,China University of Petroleum - Beijing | And 9 more authors.
Oilfield Chemistry | Year: 2014

Aimed at the certain reservoir with formation temperature of 82°C, a comb copolymer flooding was probed, the physical and chemical properties of the comb copolymer was evaluated, such as high temperature resistance, shearing rheological property, shear stability, long term stability and salt resistance; then, dynamic flooding experiments were carried out, and the slug size, the slug concentration and the way of injection method were screened. The resulted showed that the viscosity retention rate of comb polymer solutions with the concentration of 1500-2000 mg/L was still more than 40% after aged at the temperature of 82°C for 30 days. The viscosity of comb polymer solution decreased by only 8.95 mPa · s after sheared at the speed of 1500 r/min for 120 minutes. The comb polymer had more excellent temperature resistance and salt resistance than that the common polymer and the comb polymer solution and belonged to a typical non-Newtonian fluid. The oil displacement experiments showed that the larger the slug size the more the recovery efficiency under the condition of the same slug concentration, and the higher the slug concentration the more recovery efficiency under the condition of the same slug size. The optimal slug concentration was 2000 mg/L, the optimal slug size was 0.3 PV, and the way of injection was complete injection.


Zhao F.,China University of Petroleum - Beijing | Zhao F.,China National Petroleum Corporation | Zhao F.,Key Laboratory of Petroleum Engineering | Li Z.,China University of Petroleum - Beijing | And 9 more authors.
Xinan Shiyou Daxue Xuebao/Journal of Southwest Petroleum University | Year: 2016

The important prerequisite ensuring the application effect of ASP flooding is determined by the extent of the impact of characteristic parameters variations of reservoir. The variations of the characteristic parameters such as wettability, sensitivity, porosity, permeability of cores, which were drilled before and after ASP flooding in Daqing Oilfield, are analyzed systematically by core-flooding experiments and AFM. The measurement results of relative permeability show that the wettability of reservoir core will change from oil wet to water wet after ASP flooding. The sensitivity experiments indicate that ASP flooding will lead to different influence on types of sensitivity, mainly including the increase of water sensitivity, but the decrease of sensitivity of velocity, acid and alkali. Statistical analysis of the reservoir porosity and permeability shows that both the absolute value of porosity and permeability of core increase and they relatewell with each other. The observations of AFM for microscopic pore structure of core further validate the understanding of the porosity and permeability improvement. © 2016, Science Press. All right reserved.


Leng G.-Y.,China University of Petroleum - Beijing | Leng G.-Y.,China National Petroleum Corporation | Leng G.-Y.,Key Laboratory of Petroleum Engineering | Zhao F.-L.,China University of Petroleum - Beijing | And 12 more authors.
Oilfield Chemistry | Year: 2014

Using double-layer heterogeneous core model, fully playing advantages of profile control and oil displacement, the improving oil recovery effect of eight projects in different permeability contrast conditions was evaluated. The results showed that the water ratio decreased about 15% and oil recovery increased 6.7% and 8.3% in ASP flooding and polymer flooding respectively, when the permeability of core was 30 × 10-3/1000 × 10 3 um2. After modified-starch gel was formed, the water cut of ASP flooding declined to 44%, which was significantly less than the lowest value of polymer flooding (60%) and water flooding (70%), and the oil recovery increase was 23.5%, 19.2% and 10.1% in ASP flooding, polymer flooding and water flooding respectively. ASP flooding could effectiv start the lower permeability layer and produce better exploitation results than polymer flooding. The oil recovery increase of "modified-starch gel + ASP flooding" was 40.4%, which was better than the oil recovery sum of separately using modified-starch gel and ASP flooding (35.6%), and 4.3 percent higher than that of "chromium gel+ASP flooding". When the permeability was 30× 10 -3/2000 × 10μm2 and 30 × 10- 3/500 × 10μm2, the oil recovery increase of "modified-starch gel + ASP flooding" was 45.3% and 34.4%, and the oil recovery of ASP flooding increased 25.1% and 22.2%, respectively, which indicated that the more severe reservoir heterogeneity, the better exploitation results of combination flooding was.

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