Wei, Bing (Southwest Petroleum University) | Wang, Yuanyuan (Southwest Petroleum University) | Chen, Shengen (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Ning, Jian (Southwest Petroleum University) | Wang, Wanlu (Southwest Petroleum University)
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Zhao, Tianhong (Southwest Petroleum University) | Chen, Ying (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University) | He, Yi (Southwest Petroleum University) | Zhang, Yiwen (Southwest Petroleum University)
Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement.
In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.
Wei, Bing (Southwest Petroleum University) | Zhang, Xiang (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Xu, Xingguang (The Commonwealth Scientific and Industrial Research Organization) | Yang, Yang (The Commonwealth Scientific and Industrial Research Organization) | Chen, Bin (CNOOC Enertech-Drilling & Production Co.)
Although the low salinity effect (LSE) in enhanced oil recovery (EOR) is widely accepted, its underlying mechanisms have not conclusively determined largely due to the complex interactions at oil/brine/rock interfaces and their relation with the dynamic flow behaviors in porous media. Given the vast diversity of brine composition in different reservoirs, the current studies are not yet sufficient to map the complicate interfacial behaviors. Therefore, the attention of this work was placed on the events that occurred on oil/brine/rock interfaces through direct measurements of oil water IFTs, interfacial dilational rheology, zeta potential and oil water relative permeability in sandstone porous media. The effect of brine composition including ion types, salinity and valency on LSWF was examined for the intent of re-defining the potential-determining-ions (PDIs) for LSE. The results showed that the oil water interfacial behaviors closely depended on the brine composition. The wettability alteration of the sandstone surface was found to be associated with the divalent ions and the double layer expansion (DLE) failed to interpreted the observed wettability in our work. The injection of MgSO4 brine produced the highest oil recovery factor compared to other three brine. On the basis of the previous observations, we concluded that the LSE was strongly dependent on the events occurred on the oil-brine-solid interfaces. The most significant LSE was observed at a salinity of 2000ppm in our work and the ions of Mg2+ and SO42− appeared to be critical for LSWF.
Wei, Bing (Southwest Petroleum University) | Qinzhi, Li (Southwest Petroleum University) | Wang, Yanyuan (Southwest Petroleum University) | Gao, Ke (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Sun, Lin (Southwest Petroleum University)
In this work, a novel nano-suspension (NS), which was mainly composed of a surface functionalized nanocellulose, was successfully developed for "green" chemical EOR use. The rheological analysis indicated that this NS was a pseudo-plastic (shear-thinning) fluid and presented noticeable viscoelasticity. The oil displacement behaviors of this NS were thoroughly examined using core flooding methods. The EOR efficiency dependence of the NS on permeability, oil viscosity and injected volume was included. The experimental results showed that the NS flooding (NSF) further improved the oil recovery by 3-17% on the basis of water flooding. Furthermore, micro flow tests were conducted in a visual micro-model to study its flow behaviors in porous media and EOR mechanisms. Through the micro-model, the displacement behaviors and mechanisms including emulsification, dragging/squeezing and wettability alteration, were visually observed. These properties promise this NS as a green displacement agent for chemical EOR.
Wei, Bing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Ning, Jian (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Shang, Jing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Pu, Wanfen (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
The depression of the current global oil market renders the majority of chemical EOR projects worldwide unprofitable, especially in china. Therefore, economic alternative technologies must be quickly developed. This paper evaluated the potential of a smart pre-formed emulsion flooding EOR in Block 9 based on the reaction between alkali and highly acidic crude oil. The static properties and dynamic displacement behaviors of the emulsion were thoroughly investigated. Particular emphasis was placed on the relationship between emulsion stability, droplet particle/pore radius matching, and EOR efficiency. The experimental results showed that the petroleum acids of the crude oil reacted with alkali (NaOH), and producing neutral emulsions (pH≈7.0). The emulsion rheology and morphology were strongly dependent on oil water ratio. From the economic point, the oil/water ratio of 0.5:9.5 was used to prepare two types of O/W emulsions (unstable and stable emulsions) with different particle sizes. The core flooding tests proved that a higher pressure during emulsion injection was generated than that of water injection due to Jiamin effect induced by the dispered oleic phase. As a consequence, the oil recovery factor was further improved by 6-17%. High matching factor and emulsion stability accounted for more significant EOR effect as we observed.
Wei, Bing (Southwest Petroleum University) | Li, Qinzhi (Southwest Petroleum University) | Li, Hao (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University)
The environmental issues of the traditional oilfield chemistries are challenging the Enhanced Oil Recovery (EOR) industry. Therefore, eco-friendly chemical EOR methods must be quickly developed. In this work, an abundant natural polymer on earth, nano-cellulose, was extracted from the plant-based materials and then introduced to EOR. On the basis of the original nano-cellulose, a series of surface-grafting were performed for the interest to make it more favorable for EOR application, thus generating the well-defined nano-cellulose based nano-fluids. The EOR related properties including morphology, thermal stability, rheology,
Wei, Bing (Southwest Petroleum University) | Zhang, Xiang (Southwest Petroleum University) | Wu, Runnan (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Li, Yibo (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Jin, Fayang (Southwest Petroleum University) | Wang, Chongyang (Southwest Oil and Gas Field Company.)
CO2 based gas injection techniques for enhanced oil recovery (EOR) coupled with offsetting greenhouse gas emissions have received significant attention. In this work, a tight geological reservoir in China was focused. To further unlock the reserves after a natural depletion, the technique of SCCI was therefore suggested. The interest of this paper was to study the production response of the tight reservoir to SCCI and CO2 sequestration efficiency during this process. As a result of CO2 dissolution, the viscosity of the crude oil was gradually reduced with CO2 molar fraction and then nearly plateaued from 35 mol%. For this given reservoir, the optimal depleting pressure to implement SCCI was 20.88 MPa, which corresponded to the highest ultimate oil recovery. Moreover, the oil recovery increased linearly with CO2 slug size due to the pressurizing effect and viscosity reduction, which thus led to 11% of incremental oil recovery after a natural depletion. However, the oil production rate was found to rapidly decline with the decrease of core pressure. Due to the limited gas diffusion, the oil recovery steeply dropped with the cycle number and only 0.5% of oil was produced at the third cycle, indicating the insufficiency of SCCI to further mobilize the oil in place. During the SCCI, more than 85% of the injected CO2 species have been retained in the tight porous media.
Han, Xiaodong (CNOOC, Ltd, Tianjin Branch) | Liu, Yigang (CNOOC, Ltd, Tianjin Branch) | Wang, Qiuxia (CNOOC, Ltd, Tianjin Branch) | Zou, Jian (CNOOC, Ltd, Tianjin Branch) | Liu, Hao (CNOOC, Ltd, Tianjin Branch) | Wang, Hongyu (CNOOC, Ltd, Tianjin Branch) | Zhang, Xiang (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University)
Limited by platform space and equipment capability, thermal fluid injection was conducted for each individual well during heavy oil development with cyclic steam and flue gas stimulation in NB35-2 Oilfield. The single well injection mode results in severe gas channeling from injection well to adjacent production wells caused by areal pressure imbalance and high development cost. Measures must be taken to improve the recovery effect and economic benefits, especially in the low oil price environment.
The idea of multi-well simultaneous steam stimulation for offshore heavy oilfield was proposed and applied for actual practice in NB35-2 Oilfield. According to reservoir simulation results, formation pressure distribution could be much more even when thermal fluid was injected into the formation from different wells simultaneously. Besides, the overall developing cost could be greatly reduced by lowering the integral operating cost. For further controlling the gas channeling, the foam and temperature-sensitive gel were also used for gas channeling plugging. Based on the capacity of current steam and gas generator, two thermal wells were selected for field trail.
During the simultaneous steam and flue gas injection process of well X1 and X2, no gas channeling phenomenon occurred from the injection wells to adjacent wells which means that no negative impact on the production wells was induced by the injection operation. And the multi-well simultaneous steam stimulation combined with chemical plugging has displayed positive effects in controlling gas channeling. The daily oil production rate of these two wells were increased from 28.77 m3/d to 38.87m3/d, and 23.68 m3/d to 35.71 m3/d, respectively when compared with its value before steam injection. The predicted overall incremental oil production amount is about 5250 m3, and the period of validity is about 180 days. More importantly, compared with the operating cost of previous single well injection mode, the commuted operating cost of the multi-well simultaneous stimulation for one single well is greatly decreased by about 45 % and this kind of operating mode will surely bring more economic benefits.
This is the first time that multi-well simultaneous steam stimulation for offshore heavy oilfields is proposed and put into field trial. The favorable application result indicates that this technology could provide a useful guidance for the high-efficient heavy oil exploitation of offshore oilfield.
Xue, Yan (Southwest Petroleum University) | Wang, Xinyong (Southwest Petroleum University) | Zhang, Bo (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University) | Ye, Zhongbin (Southwest Petroleum University)
The swellable hydrogel particles have been developed as effective plugging agents. However, the harsh conditions would significantly detract the performance of conventional plugging agents. To address the problem, an amphoteric hydrogel (IHPA) modified by zwitterionic groups was successfully developed, which presented distinctive thermo- and salt-responsiveness. Environment Scanning Electron Microscopy (ESEM) images of swollen IHPA showed its multiporous structure contributing to its water absorptivity. The water absorption and swelling capacity of IHPA were systematically studied at various temperatures using water and different salines. The sudden increase of the swelling capacity of the hydrogels upon temperature and/or salinity, caused by the alteration of zwitterionic self-association, promised them as intelligent plugging agents. The plugging simulating tests indicated that IHPA possessed excellent plugging performance at 80°C with a plugging efficiency of 93.8% compared with the efficiency of only 33.3% at 20°C
Wei, Bing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation Southwest Petroleum University) | Pang, Shishi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation Southwest Petroleum University) | Pu, Wanfen (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation Southwest Petroleum University) | Lu, Laiming (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation Southwest Petroleum University) | Wang, Chongyang (Zitong Gas Production Region of Northwest Sichuan Gas Field Southwest Oil and Gas Field Company) | Kong, Lingle (Shengli Oilfield Ltd.)
N2 and CO2 assisted steam huff-n-puff method has been proposed as the primary strategy to develop a new heavy oil reservoir located in the northeast of China having average oil viscosity of 5000mPa·s, reservoir pressure of 14MPa and temperature of 56°C. Prior to field application, a laboratory study from phase behavior to numerical simulation was conducted in this work. The experimental data showed that the swelling of the heavy oil as a result of CO2 dissolution varied almost linearly with pressure, but appeared independent on N2 pressure. CO2 markedly outperformed N2 in swelling heavy oil reducing viscosity and extracting hydrocarbon. In huff-n-puff simulation, averagely 4% and 6% of additional heavy oil was produced by steam injection compared to CO2 and N2 injection after natural depletion. In the scenario of gas assisted steam process, a more noticeable incremental oil recovery (>10%) was produced, which thus demonstrated its potential in this reservoir. The mechanisms of oil recovery stimulation were further elucidated using numerical simulation from the point of parameter variations for pressure, viscosity, temperature, and oil saturation.