苏里格气田盒8段致密砂岩气储层滑溜水压裂渗吸实验研究

以鄂尔多斯盆地苏里格气田盒8段致密砂岩气藏储层为研究对象,对其天然岩心进行了室内自发渗吸模拟实验,具体选择采用质量法和体积法,分析研究了影响致密砂岩储层自吸的因素。实验表明,渗透率、温度因素对致密砂岩岩心渗吸采收率的影响较大,且都为积极影响。     

非常规油藏中纳米表活剂渗吸驱油效率影响的主控因素研究

随着石油开采技术的不断发展,渗吸采油也越来越受到人们的重视。然而渗吸驱油用的纳米表活剂在致密储层表面的吸附性能及影响其吸附改性效果的主控因素仍需进一步研究。通过渗吸驱油实验研究了不同因素对其吸附改性后驱油效率的影响规律,最终确定影响纳米表活剂吸附改性效果的主控因素,为提高致密油藏开发效果提供理论依据。研究结果表明;影响纳米表活剂吸附性能的因素包括化学剂种类、原油类型、温度等因素,温度及化学剂种类是影响渗吸驱油效果的主要因素,温度增大25℃,渗吸驱油效率增加幅度达到4%;相同实验条件下,化学剂A比B的渗吸驱油效率高8%,化学剂C比B的渗吸驱油效率高10%。     

表面活性剂作用下致密水湿砂岩的渗吸特征

针对致密油藏低孔低渗的特点,笔者通过核磁共振测试的方法开展了致密水湿砂岩的自发渗吸实验,研究了表面活性剂作用下的致密岩心自发渗吸驱油机理及其对不同孔隙中油相的动用程度。实验证明,小孔隙吸水大孔隙排油是致密水湿砂岩渗吸驱油的主要机理,渗吸对小孔隙中原油的动用程度远高于其他孔隙,达到了70%以上,渗吸采油可以成为致密油藏开发的一种有效开采方式。研究也发现,十二烷基硫酸钠与其他表面活性剂相比表面活性剂,在促进油滴活化,提高洗油效率等方面效果更明显,提高了渗吸效率,乳化作用可能在渗吸采油中发挥着重要的作用。     

压裂液矿化度对致密储层渗吸作用的影响

为了研究压裂液矿化度对其在致密储层中自发渗吸现象的影响,以某区块致密砂岩储层为研究对象,进行室内实验研究。研究表明,压裂液的矿化度对渗吸的影响与岩样本身有关。碳酸盐-粘土矿物比值会对矿化度的影响产生作用。研究结果对致密储层渗吸机理及压后渗吸效果具有一定指导意义。     

杭锦旗致密砂岩气藏控水压裂材料评价优选研究

致密砂岩气藏是油气田勘探开发的一个重要接替方向。杭锦旗上古生界地层水分为窜层水、凝析水、透镜体水、边底水、气层滞留水等5种类型。将一种控水表面活性剂溶液注入近井地带储层,表活剂与岩石孔壁发生界面修饰作用,通过排驱作用可以将近井地带孔喉的水逐渐排出,降低水膜厚度,增大气相渗透通道,达到控水增气的目的。对这类储层,通过室内研究,按照“疏水”的思路,开展了岩心表面修饰前后接触角测试、表面活性剂界面修饰微观特征及时效性评价、压裂过程中表活剂注入深度实验评价、界面修饰前后岩心气-水相渗实验方法优选评价控水表面活性剂控水材料,为致密砂岩气藏开发提供借鉴。     

表面活性剂在压裂液中对提高渗吸采收率的研究

针对致密砂岩油藏开展了3种表面活性剂(ZPS、SDBS、SB)在水溶液和低浓度瓜尔胶压裂液中对提高渗吸采收率的研究。只有非离子表面活性剂(SB)未起到润湿反转的作用。加有三种表面活性剂的溶液均使界面张力达到了岩心渗吸的最佳效果。分析实验得出:与注入水相比,在加有表面活性剂的溶液中对提高采收率都起到了一定的作用,在低浓度瓜尔胶压裂液中的渗吸采收率最高。改向和黏弹作用是低浓度瓜尔胶压裂液提高渗吸采收率的主要机理。     

低渗透砂岩油藏动态渗吸规律研究

低渗透砂岩油藏具有孔隙度小、孔隙压力较低、储层渗透率低等特点。为了有效地开发低渗透砂岩油藏,提高低渗透砂岩油藏采收率,通过动态渗吸实验研究了渗透率、润湿性、岩心长度、温度等因素对渗吸采收率的影响。结果表明:岩心渗透率越低,渗吸采收率越大;岩心越亲水,动态渗吸采收率越高;岩心长度越短,渗吸采收率越高;温度升高,渗吸采收率增大。     

中国致密油特征与开发思路探索

经过近半个世纪的开发与探索,我国目前对致密油已经有了初步的认识,致密油的定义、基本特征及参数标准已经有了初步的共识。通过对致密油的认识现状、开发现状进行总结与分析,认为现阶段致密油开发过程中,基质孔隙中原油动用程度极低。针对这一现状,提出了通过渗吸进行致密油开发的思路,并对渗吸开发致密油的可行性和促进致密岩心渗吸的表面活性剂优选进行了初步探索,认为表面活性剂提高渗吸采出程度的主要机制是提高驱油动力和改善油滴在喉道处的运移,因此具有润湿性能和乳化作用的表面活性剂可能成为致密油渗吸开发过程中的首选。     

碳酸盐岩油藏储层渗流特征实验研究

碳酸盐岩储层流体渗流规律与常规砂岩储层明显不同,此类储层开发过程中,存在生产井压力和产量下降快、采收率低等问题。为此,本文通过两相驱替实验分析了Sar油田储层岩心渗流规律、洗油效率及其主要影响因素。通过实验研究得出,当致密碳酸盐岩储层不存在裂缝时,储层水驱采收率仅有30%,而当存在一定裂缝时,由于储层平均渗透率增加,且存在基质和裂缝之间的渗吸作用,相比无裂缝油藏采收率可提高3%～10%,这表明,碳酸盐岩油藏在进行水驱开发时,存在一定裂缝的储层的水驱开发效果要优于不存在裂缝的碳酸盐岩储层。     

矿化度对低渗油藏渗吸作用影响的实验研究

低渗、致密油藏开发难度大,注水采收率低、效果差,利用水的自发渗吸作用驱油是一种经济有效的开发手段。文中利用鄂尔多斯盆地延长油田的岩心,研究矿化度等因素对岩心渗吸效果的影响,进行了自发渗吸实验。实验结果表明:渗吸液矿化度越低,其渗吸驱油速度越快,达到稳定状态所需时间越短。     

Surfactant-Induced Wettability Alteration of Oil-Wet Sandstone Surface: Mechanisms and Its Effect on Oil Recovery

Different analytical methods were utilized to investigate the mechanisms for wettability alteration of oil-wet sandstone surfaces induced by different surfactants and the effect of reservoir wettability on oil recovery. The cationic surfactant cetyltrimethylammonium bromide (CTAB) is more effective than the nonionic surfactant octylphenol ethoxylate (TX-100) and the anionic surfactant sodium laureth sulfate (POE(1)) in altering the wettability of oil-wet sandstone surfaces. The cationic surfactant CTAB was able to desorb negatively charged carboxylates of crude oil from the solid surface in an irreversible way by the formation of ion pairs. For the nonionic surfactant TX-100 and the anionic surfactant POE(1), the wettability of oil-wet sandstone surfaces is changed by the adsorption of surfactants on the solid surface. The different surfactants were added into water to vary the core surface wettability, while maintaining a constant interfacial tension. The more water-wet core showed a higher oil recovery by spontaneous imbibition. The neutral wetting micromodel showed the highest oil recovery by waterflooding and the oil-wet model showed the maximum residual oil saturation among all the models.     

Enhanced Wettability Alteration by Surfactants with Multiple Hydrophilic Moieties

The main production mechanism during water flooding of naturally fractured oil reservoirs is the spontaneous imbibition of water into matrix blocks and resultant displacement of oil into the fracture system. This is an efficient recovery process when the matrix is strongly water-wet. However, in mixed- to oil-wet reservoirs, secondary recovery from water flooding is often poor. Oil production can be improved by dissolving low concentrations of surfactants in the injected water. The surfactant alters the wettability of the reservoir rock, enhancing the spontaneous imbibition process. Our previous study revealed that the two main mechanisms responsible for the wettability alteration are ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface. Based on the superior performance of surfactin, an anionic biosurfactant with two charged groups on the hydrophilic head, it was hypothesized that the wettability alteration process might be further improved through the use of dimeric or gemini surfactants, which have two hydrophilic head groups and two hydrophobic tails. We believe that when ion-pair formation is the dominant wettability alteration mechanism, wettability alteration in oil-wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule since the ion-pair formation is driven by electrostatic interactions. At a concentration of 1.0 mmol L⁻¹ a representative anionic gemini surfactant showed oil recoveries of up to 49% original oil-in-place (OOIP) from oil-wet sandstone cores, compared to 6 and 27% for sodium laureth sulfate and surfactin, respectively. These observations are consistent with our hypothesis.     

Experimental Investigation into the Screening of New Surfactant Flowback Aids and Statistical Interpretation of Their Imbibing Capacity for Selected Core Substrates

Spontaneous imbibition is a pervasive part of many natural and industrial processes. As an inherent feature of fluid transport in porous media, it is a driver for oil recovery. Understanding spontaneous imbibition and leveraging surface science is fundamental for fluid recovery; specifically, the role of the surfactant in the imbibition processes and the potential to alter capillarity and wettability of reservoir rock. Surfactant success relies on the understanding of the factors governing the interfacial phenomena among crude oil, and formation properties under reservoir conditions. Developing a methodology coupling chemical performance with analytical techniques, and statistical interpretation of core/surfactant/oil interactions, can help establish workflows to advance new chemistries and enhance oil recovery. This article discusses a study of flowback aids formulated as microemulsions corresponding to the thermodynamically stable Winsor Type IV solutions. Neat formulated microemulsions, when dosed at field treatment concentrations, provide either oil-in-water droplet microemulsions or nanoemulsions. The solvency potential was measured, and the Kauri-butanol (Kb) value was determined. Parameters such as critical micelle concentration (CMC) and interfacial tension (IFT) were determined to characterize microemulsion solutions. These systems were tested using either in the column flow test with formation material sieved to match mineral grain size, or sandstone cores of various permeabilities. The results indicate that surfactant-based flow-enhancing aids are desirable for improved oil recovery when compared to the control fluid. The statistical analysis of core-fluid interaction includes an ANOVA followed by assumption evaluations and model interpretation, which demonstrates that the core permeability term, followed by the surfactant term, has the highest contribution whereas oil has no statistical significance to the model.     

Wettability reversal of reservoir rock surface through surfactant stabilized microemulsion

In the process of the tertiary recovery of oil and gas resources, it is necessary to use external fluids to displace the crude oil in the reservoir. Whether the crude oil on the surface of the rock can be effectively displaced and the wettability of the rock can be changed to avoid re-adsorption by the crude oil is directly related to the level of oil recovery. Therefore, it is critical to study the cleaning and wettability reversal of reservoir rock surface. Because microemulsions have outstanding performance in changing the wettability of rocks and solubilizing crude oil, this paper uses cetyl trimethyl ammonium bromide (CTAB) as a surfactant and n-butanol as a co-surfactant to prepare microemulsions. The performance of microemulsions with different microstructures on the cleaning and wettability changes of crude oil on the rock surface were studied. The results show that the water-in-oil (W/O) microemulsion has good cleaning efficiency, and the oil removal rate on the sandstone core surface can reach 79.65%. In terms of changing the wettability of the rock surface, W/O, bi-continuous phase (B.C.) and oil-in-water (O/W) microemulsions can change the core surface from lipophilic to hydrophilic. And the effects of the B.C. and O/W microemulsions are more obvious. The microemulsion system that was prepared based on cationic surfactants has a good application prospect in changing the wettability of the reservoir and cleaning the adsorbed crude oil.     

表面活性剂对特低渗油藏的适用性及应用

为评价表面活性剂WLW对特低渗油藏的适用性,研究了WLW的渗吸特性、乳化性能和界面张力及其在特低渗油藏物理模拟岩心驱油实验和现场中的应用。室内实验结果表明,WLW对注入水的渗吸效率有促进作用;注入质量分数0.2%的WLW溶液,可在水驱基础上提高驱油效率5%左右;WLW在特低渗岩心中提高驱油效率的幅度明显高于中低渗岩心。2011—2013年在长庆靖安油田A1和A2井组开展注WLW现场试验,累计增油4 781 t,WLW对于特低渗油藏提高采收率效果明显。     

Laboratory Studies to Determine Suitable Chemicals to Improve Oil Recovery from Garzan Oil Field

Garzan oil field is located at the south east of Turkey. It is a mature oil field and the reservoir is fractured carbonate reservoir. After producing about 1% original oil in place (OOIP) reservoir pressure started to decline. Waterflooding was started in order to support reservoir pressure and also to enhance oil production in 1960. Waterflooding improved the oil recovery but after years of flooding water breakthrough at the production wells was observed. This increased the water/oil ratio at the production wells. In order to enhance oil recovery again different techniques were investigated. Chemical enhanced oil recovery (EOR) methods are gaining attention all over the world for oil recovery. Surfactant injection is an effective way for interfacial tension (IFT) reduction and wettability reversal. In this study, 31 different types of chemicals were studied to specify the effects on oil production. This paper presents solubility of surfactants in brine, IFT and contact angle measurements, imbibition tests, and lastly core flooding experiments. Most of the chemicals were incompatible with Garzan formation water, which has high divalent ion concentration. In this case, the usage of 2-propanol as co-surfactant yielded successful results for stability of the selected chemical solutions. The results of the wettability test indicated that both tested cationic and anionic surfactants altered the wettability of the carbonate rock from oil-wet to intermediate-wet. The maximum oil recovery by imbibition test was reached when core was exposed 1-ethly ionic liquid after imbibition in formation water. Also, after core flooding test, it is concluded that considerable amount of oil can be recovered from Garzan reservoir by waterflooding alone if adverse effects of natural fractures could be eliminated.     

Superior enhancement of imbibition recovery by novel surfactant mixtures with a large hydrophobic group combined with nanosilica

Low interfacial tension (IFT) drainage and imbibition are effective methods for improving oil recovery from reservoirs that have low levels of oil or are tight (i.e., exhibit low oil permeability). It is critical to prepare a high efficient imbibition formula. In this work, a novel 2,4,6-tris(1-phenylethyl)phenoxy polyoxyethylene ether hydroxypropyl sodium sulfonate (TPHS) surfactant was synthesized and evaluated for imbibition. Its structure was confirmed by Fourier transform infrared spectroscopy and the interfacial tension (IFT) of the crude oil/0.07% TPHS solution was 0.276 mN/m. When 0.1 wt% TPHS was mixed with 0.2 wt% alpha olefin sulfonate (AOS), the IFT was lowered to 6 × 10⁻² mN/m. The synergy between nanoparticles (NPs) and TPHS/AOS mixed surfactant was studied by IFT, contact angle on sandstone substrates, zeta potential, and spreading dynamics through microscopic methods. The results show that the surfactant likely adsorbs to the NP surface and that NP addition can help the surfactant desorb crude oil from the glass surface. With the addition of 0.05 wt% SiO₂ NPs (SNPs), the imbibition oil recovery rate increased dramatically from 0.32%/h to 0.87%/h. The spontaneous imbibition recovery increased by 4.47% for original oil in place (OOIP). Compared to flooding by TPHS/AOS surfactant solutions, the oil recovery of forced imbibition in the sand-pack increased by 12.7% OOIP, and the water breakthrough time was delayed by 0.13 pore volumes (PV) when 0.05% SNPs were added. This paper paves the way for enhanced oil recovery in low-permeability sandstone reservoirs using novel TPHS/AOS surfactants and SNPs.     

裂缝性低渗透碳酸盐岩脉冲注水实验研究

在裂缝性低渗透碳酸盐岩油藏,毛管自吸作用使润湿相进入喉道将原油从多孔基质岩块驱至裂缝,在油田开发中,采用脉冲注水方式和合理的开发参数能够有效的利用渗吸作用来改善该类油藏的水驱开发效果,有助于提高石油的采收率。本文通过大量的室内实验研究,分析碳酸盐岩岩芯自然渗吸规律和脉冲注水对注水驱油效果的影响,研究合理的注水参数。川中碳酸盐岩油藏基岩物性差,自然渗吸驱油效率低;脉冲注水比自然渗吸可提高驱油效率0．608～8．916个百分点,提高幅度与脉冲注水压力、注水周期和脉冲次数有关。研究成果对该类油藏合理注水开发方式具有参考作用。     

A new surfactant wettability alteration model for reservoir simulators

Surfactants enhance oil recovery in naturally-fractured oil-wet rocks by wettability alteration and interfacial tension reduction. The oil-wet state is ascribed to the adsorption of soap on the rock surface. Soaps are the dissociated forms of carboxylic acids in the crude oil, that is, carboxylate surfactants. This paper describes a new mechanistic surfactant wettability alteration model that was developed for and implemented in a reservoir simulator. The model captures the geochemical reactions of acid/soap, the formation of mixed micelles, Henry's law adsorption, and the formation of cationic surfactant-anionic soap ion-pairs. A new wettability scaling factor is used to interpolate between the oil-wet and water-wet relative permeability and capillary pressure curves. The new model also accounts for the effect of salinity and pH, so it should also be useful for modeling low-salinity flooding without surfactant. Previous surfactant wettability alteration models ignored the underlying mechanisms and were not predictive. Simulations of both static and dynamic imbibition were performed to better understand the key surfactant parameters and the dynamics of wettability alteration, microemulsion phase behavior, and interfacial tension reduction on oil recovery. Optimizing surfactant formulations for wettability alteration is discussed.     

乳化/润湿耦合作用稠油流动减阻新思路

稠油节能增输是解决常规原油日渐枯竭、保障原油接替的紧迫需求,然而稠油黏度高、流道黏附性强,使其输送异常困难,是稠油节能增效输送技术瓶颈。根据前期研究本文作者发现,活性水作用下稠油乳化降黏的同时可改变稠油与管内壁界面特性,以及稠油提高采收率——润湿性之润湿反转,提出管输稠油乳化降黏及其流固界面润湿耦合作用流动减阻新思路。本文基于国内外相关研究成果的系统分析,探讨稠油乳化降黏、流固界面润湿及耦合减阻的有效性,剖析活性水作用乳化/润湿耦合减阻存在的主要问题,理论分析稠油在管输过程中实现乳化/润湿耦合减阻的可行性。结果表明,乳化/润湿减阻思路在理论上是可行的,而且在表面活性剂作用下乳化降黏的同时管输流固界面润湿反转更容易实施,然而,乳化/润湿减阻实际应用缺乏充分认识尚需深入研究其相关科学问题;其深入研究有望理解与认识流固界面特性对流动阻力的影响作用,可解决管输稠油流动阻力之难题,将为稠油流动改进提供理论与技术支撑,在稠油管输节能增效方面具有广阔的应用前景。