Recently, there are increasing interests in chemical enhanced oil recovery (EOR) especially surfactant-polymer (SP) flooding. Although alkali-surfactant-polymer (ASP) flooding can make an incremental oil recovery factor (IORF) of 18% original oil in place (OOIP) according to large-scale field tests in Daqing, the complex antiscaling and emulsion breaking technology as well as potential environment influence makes some people turn to alkali-free SP flooding. With the benefit of high IORF in laboratory and no scaling issue to worry, SP flooding is theoretically better than ASP flooding when high quality surfactant is available. Many SP flooding field tests have been conducted in China, where the largest chemical flooding application is reported. 10 typical large-scale SP flooding field tests were critically reviewed to help understand the benefit and challenge of SP flooding in low oil price era. Among these 10 field tests, only one is conducted in Daqing Oilfield, although ASP flooding has entered the commercial application stage since 2014. 2 SP tests are conducted in Shengli Oilfield. Both technical and economic parameters are used to evaluate these tests. 2 of these ten tests are very successful; the others were either technically or economically unsuccessful. Although laboratory tests showed that SP flooding can attain IORF of more than 15%, the average predicted IORF for these 10 field tests was 12% OOIP. Only two SP flooding tests in (SP 1 in Liaohe and SP 7 in Shengli) were reported actual IORF higher than 15% OOIP. The field test in Shengli was so successful that many enlarged field tests and industrial applications were carried out, which finally lead to a commercial application of SP flooding in 2008. However, other SP projects are not documented except two (SP7 and SP8). SP flooding tests in low permeability reservoirs were not successful due to high surfactant adsorption. It seems that SP flooding is not cost competitive as polymer flooding and ASP flooding if judged by utility factor (UF) and EOR cost. Even the most technically and economically successful SP1 has a much higher cost than polymer flooding and ASP flooding, SP flooding is thus not cost competitive as previously expected. The cost of SP flooding can be as high as ASP flooding, which indicates the importance of alkali. How to reduce surfactant adsorption in SP flooding is very important to cost reduction. It is high time to reevaluate the potential and suitable reservoir conditions for SP flooding. The necessity of surfactant to get ultra-low interfacial tension for EOR remains further investigation. This paper provides the petroleum industry with hard-to-get valuable information.

The recovery efficiency by polymer flooding is 10% higher than that of water flooding for main reservoirs in Daqing Oil Field, and yearly oil production rate by polymer injection has continuously reached over 10 million tons for 8 years. However, to further enhance oil recovery, it is very important to know how many oil remained in the reservoirs after polymer injection as well as its distribution. The paper took use of logging data of 200 new drilling wells to make macro analysis on remaining oil distribution after polymer injection, and based on the data of coring wells, collected from the same well group in Western Fault of B1 Region, before and after polymer flooding, respectively, core membrane fluorescence technology was used to conduct the analysis on microscopic remaining oil distribution. The macro analysis results indicate that swept thickness of the reservoir increased 21.4% from 68.6% of water flooding to 90% of polymer flooding, and oil saturation reduced 11.9% from 52.8% to 40.9%, and displacement efficiency has went up 7.6 percentages. The residual oil distribution after polymer flooding is scattered in horizontal direction, while it is interleaved in vertical direction. Following polymer flooding, 10.6% unswept thickness is mainly distributed in thick oil layers, and most of remaining oil within thick oil layers lies in the interlayers and at the top of thick oil layers, which its effective thickness is close to 80%. From the macro point, remaining oil is mainly located in distributary line or some places where injection and production relation is imperfect or the phase is changed, and oil saturation located in distributary line is 4.4 percentages higher than that along mainstream line. The micro analysis results show that the behavior of remain oil distribution is similar to water flooding, which is mainly controlled by capillary force.

Polymer flooding has drawn more and more attention in the world for its high incremental oil recovery factor and relative low costs compared with water flooding and other chemically enhanced oil recovery techniques. However, for many oilfields, such as Daqing Oilfield, China, that have already been flooded with polymers, how to further improve recovery remains a big problem. Traditional intralayer, interlayer and plane heterogeneity studies cannot accurately characterize the remaining oil distribution after polymer flooding. To solve this problem, we established a method to quantitatively describe the reservoir’s architecture. Then, the architecture elements were dissected hierarchically and the interface of each architecture level in Daqing Oilfield was identified. The distribution pattern and development potential of the remaining oil after polymer flooding under the influence of reservoir architecture was analyzed. The results show that, regarding the sedimentary process from north to south in Daqing Oilfield, the channel becomes narrower, the thickness decreases, the point bar’s width increases and the thickness of the meandering river decreases. The braided bar scale becomes larger and the thickness becomes smaller in the braided river. According to the reservoir’s architecture, the remaining oil was divided into four categories of plane remaining oil (abandoned channel occlusion type, interfluvial sand body occlusion type, inter-well retention type and well pattern uncontrollable type) and three types of vertical remaining oil (in-layer interlayer occlusion type, rhythm type and gravity type). About 40% of the original oil in place (OOIP) of Daqing Oilfield has not yet been produced, which indicates that there is great potential for development. This study is important for improving oil recovery in polymer-flooded reservoirs.

The flow field is the fluid dynamic flow path in strongly heterogeneous reservoirs, and its evolution significantly affects the distribution of remaining oil, showing a disordered and highly dispersed mode caused by long-time water injection. By combining traditional flow-field evaluation with flow diagnostics, this paper proposes a methodology to quantitatively characterize and adjust the flow field in real time during the late stage of waterflooding in strongly heterogeneous reservoirs. In the study, the fluid velocity, abundance of predominant remaining oil, and Lorenz coefficient are preferred as the characteristic parameters to evaluate the effect of reservoir and flow heterogeneity on the flow field. Taking the minimization of the Lorentz coefficient as the objective function, the optimal injection and production parameters are obtained by dynamic adjusting the flow field. The results show that as water injection continues, the shape and variation of the flow field are jointly influenced by the reservoir rhythm, vertical permeability contrast, and lateral permeability distribution. The larger the permeability contrast, the greater the influence of the lateral permeability distribution. When the permeability contrast is large, the Lorenz coefficient strongly depends on the lateral permeability distribution. Finally, this method is applied to an actual heterogeneous reservoir, and a better effect of oil increase and water reduction is achieved.

Tight oil reservoirs require fracturing techniques to create complex fracture networks for efficient development. It is frequently accompanied by a dynamic matrix-fracture imbibition process, promoting enhanced recovery. At present, the mechanism of three dimensions (3D) matrix-fracture dynamic imbibition at the pore scale has not been fully elucidated. In this paper, the dynamic imbibition process of oil-water two phases in matrix-fracture was simulated based on the Navier–Stokes equations, and the level set method was used to capture the real-time interfacial changes between the two phases. It was found that during matrix-fracture dynamic imbibition process, oil-phase droplets in a single pore remain in the pore mainly due to the “stuck” effect. Cluster residual oil in the pore space is mainly retained due to the “flow around” effect. Continuous residual oil in the deeper regions of the matrix is due to insufficient capillary force. Water phase in the micro-confinement space of a tight reservoir intrudes into the pore space along the pore corners, forming the “fingering” phenomenon is beneficial for enhancing the efficiency of micro-dynamic imbibition. It differs from cognition obtained in the micro-view space during conventional water flooding. The enhancement of imbibition efficiency is often accompanied by the occurrence of fluctuations in the average pressure within the matrix. Therefore, a method involving impulse type of high-frequency and short-period for supplemental energy and imbibition is suggested to enhance recovery in tight sandstone reservoirs. This study reveals the detailed mechanisms of oil-water two-phase transport at different stages in the dynamic imbibition process and holds significant guiding implications for enhancing recovery in this type of reservoirs.

In order to explore the influence of water dilution on performance of Cr³⁺ polymer weak gel in porous medium, the performances of pure polymer solution and Cr³⁺ polymer weak gel were studied according to the laboratory testing of viscosity, micro-structure performances (polymer molecule aggregate dimension, polymer molecule aggregate configuration and Zeta potential), seepage characteristics and oil displacement effect under the condition of water dilution. The results indicated that, after diluting by water, pure polymer solution and Cr³⁺ polymer weak gel had an almost same viscosity, but there were obvious differences in micro-structure performance and seepage characteristics. Different with pure polymer solution, with the decrease of polymer concentration, on the one hand, the influence of free Cr³⁺ on electric double layer and shielding effect on electrostatic exclusion got weaker, on the other hand, water molecules were attracted by hydrophilic groups on the Cr³⁺ polymer weak gel molecular chains and then entered into the three-dimensional spatial structure of Cr³⁺ polymer weak gel, producing hydration and expansion. Therefore, the polymer molecule aggregate dimension of Cr³⁺ polymer weak gel presented a trend of continuous increasing. This characteristic was good for keeping the injection pressure at a higher value during diluting in the porous medium, which could be used to improve oil recovery in offshore oilfield through conducting injection of water-alternating- Cr³⁺ polymer weak gel.