Experimental investigations of fracturing fluid flowback and retention under forced imbibition in fossil hydrogen energy development of tight oil based on nuclear magnetic resonance

Experimental works have proved that imbibition under forced pressure (FP, the difference between hydraulic fluid pressure and original pore pressure) has a positive effect on fossil hydrogen energy development in tight oil reservoir. However, the knowledge of the influence of imbibition under forced pressure (forced imbibition, FI) on fracturing fluid flowback and water retention is still limited. In this paper, experiments were designed and conducted to reveal the mechanism of fracturing fluid flowback and water retention under imbibition effect in tight sandstones. As a comparison, unconsolidated sandstones were also investigated in this study. Core samples were divided into two categories: the imbibition ones (treated by imbibition) and the filtration ones (treated by displacement), in accordance with the real oil-water distribution after well shut-in. An imbibition core and a filtration core were stitched together to conduct a flowback experiment. During the experiment, fluid distribution in different pore sizes was monitored continuously by using a low-field nuclear magnetic resonance device. Results show that the flowback recovery in tight sandstones is much lower than that in unconsolidated sandstones due to the difference of pore structure. Meanwhile, forced imbibition leads to higher oil recovery than spontaneous imbibition (SI) in tight sandstones since forced pressure enhances water imbibition. The water imbibed into small-macro and macro pores contributes the major flowback recovery, but the imbibed water in micro pores is rather difficult to displace and finally retains in these pores during the flowback process. Overall, forced imbibition not only enhances oil recovery but also increases water retention, explaining the mechanism of well productivity increase by using the shut-in method in the field. This study can help to clarify the influence of forced imbibition on fracturing fluid flowback and enhancement of fossil hydrogen development, and further provide guidance for flowback designs.     

Spontaneous Imbibition Experiments of Enhanced Oil Recovery with Surfactants and Complex Nano-Fluids

Two types of porous media were analyzed with the intention of exploring alternative enhanced oil recovery methods. Core samples were taken from the Tensleep Formation of the Black Mountain Field in Hot Springs County, WY. The lithology is mainly sandstone and dolomite. The measured effective porosity values ranged from 13.0 to 18.0%, and permeabilities from 19 to 68 md. Production from the Tensleep and Phosphoria formations using conventional methods has resulted in a low secondary recovery factor, possibly due to high capillary forces and an oil-wet formation. Different surfactants were investigated to determine the viability of a possible enhanced oil recovery process using a spontaneous imbibition process in Amott cells. A very high enhanced recovery factor of more than 89% was achieved using a complex nano-fluid that consists of a mixture of surfactant, solvent, co-solvent and water. These recovery factors compared with 13% by brine imbibition and up to 21% using commercial surfactants. At the other end of the scale, very high porosity volcanic pumice was also subjected to the same tests. For this rock the porosity values ranged from 65 to 90% and permeabilities were 2.0–2.7 d. Secondary recovery showed values up to 81% on spontaneous imbibition and up to 91% when surfactants were employed. These experimental results indicate that pumice has favorable reservoir characteristics, but, due to its weak brittle nature, it would not be expected that it could withstand the overburden stress at any significant depth. However, it does represent a useful laboratory specimen.     

压裂液存留液对致密油储层渗吸替油效果的影响

统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现,存地液量越大,一年累积产量越高,与常规的返排率越高产量越高概念恰恰相反,可能与存地液的自发渗吸替油有关。核磁实验结果表明,渗吸替油不同于驱替作用,渗吸过程中小孔隙对采出程度贡献大,而驱替过程中大孔隙对采出程度贡献大,但从现场致密储层岩心孔隙度来看,储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素,探索影响压裂液油水置换的关键影响因素,得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明,各参数对渗吸速度的影响顺序为:界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大,渗吸采收率越大,但是增幅逐渐减小;原油黏度越小,渗吸采收率越大;渗吸液矿化度越大,渗吸采收率越大;当渗吸液中助排剂浓度在0.005%~5%,即界面张力在0.316~10.815 mN/m范围内时,浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明:并不是界面张力越低,采收率越高,而是存在某一最佳界面张力,使地层中被绕流油的数量减少,渗吸采收率达到最高,为油田提高致密储层采收率提供实验指导。      

多元注水技术在裂缝性古潜山油藏的探索与实践

针对大民屯凹陷古潜山油藏注水开发过程中遇到的水窜严重、水驱采收率低等问题,加强了古潜山内幕研究,在对储层特征及剩余油分布进一步认识的基础上,将常规水驱方法与渗析采油机理相结合,发展出多种井型组合注水、古潜山分层注水、异步注采等多元化注水技术,在扩大注水波及体积、提高储量动用程度方面有良好效果。该研究对同类型古潜山油藏的开发有一定借鉴意义。     

致密油藏裂缝动态渗吸排驱规律

为明确裂缝性致密油藏注水动态渗吸特征,解决水驱采收率低下等问题,以姬塬油田延长组长6油层组为研究对象,采用高压压汞、核磁共振T₂谱、扫描电镜和铸体薄片分析等方法研究了目标储层微观孔隙结构特征,建立了3类储层分类评价标准,并对代表性岩心开展了基于核磁共振在线扫描的动态渗吸实验,模拟了水驱过程中裂缝-基质间的动态渗吸过程,从微观孔隙尺度定量表征了不同孔径孔隙原油的动用程度,评价了8个储层物性参数对动态渗吸效率的影响程度。实验结果表明,目标储层孔隙结构可划分为3类,随着储层孔隙结构变差,孔隙类型逐渐单一化、储集性能和渗流能力不断降低,导致动态渗吸效率不断下降。Ⅰ类和Ⅱ类储层动态渗吸过程可以划分为3个阶段：大孔隙在驱替作用下采出程度快速上升阶段、微小孔隙在渗吸作用下采出程度缓慢上升阶段和动态渗吸平衡阶段;而Ⅲ类储层在实验中仅存在前2个阶段。随着储层孔隙结构变差,微小孔隙动用比例增大,渗吸作用明显,虽然对岩心总采收率贡献程度增加,但总采收率低下。渗透率、可动原油饱和度、孔隙半径、可动原油孔隙度、黏土矿物含量和润湿性是影响动态渗吸效率的主要因素,对渗吸效率的影响程度依次逐渐减弱。分选系数和孔隙度是影响动态渗吸效率的次要因素,对渗吸效率的影响程度相对较小。     

考虑应力作用的煤岩水相自吸实验研究

我国煤层气储层渗透率普遍偏低,为达到合理产能需进行压裂改造。煤层气储层裂隙发育导致压裂液滤失严重,强吸附能力使流体得不到有效返排,造成储层损害降低了渗流能力,大大削弱了增产改造的效果。开展了煤岩水相自吸实验,系统研究了煤岩水相自吸特性及应力状态的影响。结果表明,煤样渗透率越高自吸速率越大,自吸曲线可以分为自吸和扩散吸附2段,考虑应力作用自吸速率降低近一个数量级,揭示了煤岩物性和应力条件是煤岩水相自吸的影响因素。通过煤吸附水机理和煤岩孔隙结构分析指出,煤表面与水的相互作用和毛细管压力决定了水的自吸特性。研究获得的认识对煤岩气藏水相圈闭评价、压裂方式优选和压裂液设计具有借鉴意义。     

克拉玛依砾岩储集层微观水驱油机理

以克拉玛依油田六中区下克拉玛依组砾岩储集层为研究对象,从储集层特征分析和渗流机理研究着手,通过室内实验,研究砾岩储集层水驱油和渗吸过程中微观孔隙动用规律,分析孔隙结构与驱油效率关系,研究微观剩余油分布特征和长期水驱油对储集层孔隙结构的影响。研究表明：目前剩余油饱和度较高,但剩余油主要分布于小孔隙之中;水驱过程中,优先动用的是超大孔隙,对采出程度起主要贡献的是中大孔隙;渗吸过程中,优先动用的是小孔隙,对渗吸作用起主要贡献的是中小孔隙;孔隙结构是影响驱油效率和微观剩余油分布的关键因素;长期水驱后,孔隙中填隙物发生膨胀、分散、运移和溶蚀,大孔道增多,连通性变好,储集层微观非均质性进一步增强。图11表5参21     

Multiscale modeling of oil uptake in fried products

Oil–air biphasic flow has been simulated at the scale of an entire potato tuber tissue using a Kinetic Monte‐Carlo (KMC) formulation parameterized on microscopic observations. Extrapolations to more general configurations are proposed by combining the proposed KMC framework with oil momentum equations integrated at microscopic scale. Branched percolation routes in three‐dimensional honeycomb arrangement of cells are explored using a first‐passage algorithm. Three major applications are presented. KMC simulations are first considered to homogenize sparse dynamic observations at the scale of isolated cells up to the scale of a full tissue. The second application investigates the effect of cell damages on oil uptake. Finally, our general KMC formulation was successfully compared with a diffusive model of oil uptake. Comprehensive rules to set the distribution parameters of all quantities (kinetic and structure parameters) from scarce observations or general assumptions are discussed. © 2015 American Institute of Chemical Engineers AIChE J, 61: 2329–2353, 2015     

一种定量测定油藏岩石润湿性的新方法

油藏岩石润湿性是决定油藏流体在孔隙介质中的位置,流动及分布的重要因素,特别是对油,水相对渗透率和注水采收率有很大的影响。因此,它是特殊岩心分析中需测定的重要参数,目前,定量测量岩石润湿性最常用的实验方法为Amott法和USBM法,但是,这两种方法的操作程序较为复杂,尤其是USBM法需使用专用岩心设计的超高速离心机,由于设备条件限制而较少被采用,本文提出一种比较简便易行的新方法（即经改进的自吸速度法）,来定量测定岩石润湿性,早在50年代末,Bobek等人和Denekas等人都曾通通过测定岩心的自吸速度来评价岩石的润湿性,然而,由于夫法消除界面张力,孔隙结构以及流体黏度等其它因素对自吸速率的影响,他们只能用此法要相对比较不同岩石的润湿性,正如Anderson,所指出,这只是一种定性的方法,直至90年代,Morrow等人首次提出了一种通过测定自吸速度和拟毛等力曲线定量评价油藏岩石润湿性新方法,本研究在此基础上对该法又进行了石润湿性的新方法,本研究在此基础上对该法又进行了改进和完善,并将该法与Amott法的测定结果进行了比较,使之便于推广应用。