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.     

A stabilized foam formulation using FTP-SDS surfactants for wettability alteration and flow diversion in carbonate fractured oil reservoirs

Foam injection contributes to improved oil recovery through flow diversion, reduction of interfacial tension (IFT), and wettability alteration of the rock while its stability is an issue. In this article, nitrogen-foam was optimally formulated using fluorocarbon tubiguard protect (FTP) surfactant stabilized with sodium dodecyl sulfate (SDS) co-surfactant that was later experimentally considered for oil recovery in a fractured carbonate rock taken from an oil field in the Middle East. The results showed that the 5:1 volume ratio of fluorocarbon surfactant and SDS (FS51) generates a stable foaming agent with ability of changing the wettability of the carbonate rock surfaces to an intermediate gas-wet state. A series of core-flood experiments at HPHT conditions were also carried out and designed to properly represent matrix-fracture media using both a horizontally and vertically oriented setup. The oil saturated cores were flooded with nitrogen gas first followed by foam injection. It was concluded that foam can divert the gas to flow from fractures to the matrix blocks and result in a significant oil recovery. The contact angle tests that performed after core-flood experiments revealed the wettability changes of fracture surfaces from an oil-wet to a gas-wet state. This allows gas to be imbibed into the matrix blocks by capillary force and results in enhancement of ultimate oil recovery. This study revealed that trapped oil in matrixes blocks that had not been drained during the gas injection process could be produced by designing a stable foam that sustainably diverts injected fluid from fractures to matrix zone.     

Model Development for MEOR Process in Conventional Non‐Fractured Reservoirs and Investigation of Physico‐Chemical Parameter Effects

A three‐dimensional multi‐component transport model in a two‐phase oil‐water system was developed. The model includes separated terms to account for the dispersion, convection, injection, growth and death of microbes, and accumulation. For the first time, effects of both wettability alteration of reservoir rock from oil wet to water wet and reduction in interfacial tension (IFT) simultaneously on relative permeability and capillary pressure curves were included in a MEOR simulation model. Transport equations were considered for the bacteria, nutrients, and metabolite (bio‐surfactant) in the matrix, reduced interfacial tension on phase trapping, surfactant and polymer adsorption, and effect of polymer viscosity on mobility of the aqueous phase. The model was used to simulate effects of physico‐chemical parameters, namely flooding time schedules, washing water flowrate, substrate concentration, permeability, polymer and salinity concentration on Original Oil In Place (OOIP) in a hypothetical reservoir.     

超稠油开发技术现状与实例

本文对五种有潜力的超稠油开发技术分别进行了分析评价,即水平井蒸汽辅助重力泄油、出砂冷采技术、水平井注气体溶剂萃取技术、重力辅助火烧油层技术、水平裂缝辅助蒸汽驱技术。其中出砂冷采和蒸汽辅助重力泄油技术均已工业化应用并取得了良好的开发效果,如E IK Po int和辽河杜84块超稠油油藏。     

粘弹性流体在微孔道中流动的受力分析

针对亲油岩石水驱后残余油膜的存在形式及聚合物溶液的粘弹特性,选取粘弹性流体中的上随体Maxwell本构方程并使用计算流体软件Polyflow对模型进行数值分析。对比研究了在不同的松弛时间,不同的孔道宽度下,聚合物溶液作用于残余油膜上的应力T11的变化趋势,并且将水与聚合物溶液的驱替结果进行了比较。结果表明:随着聚合物溶液弹性的增强,对油膜的作用力T11就越强;孔道宽度与油膜高度越接近,对油膜的作用力就越强;聚合物溶液对油膜的作用力较水溶液强。     

A study of bitumen recovery by gravity drainage using low temperature soluble gas injection

A gravity drainage concept has been proposed and tested for in-situ recovery of bitumen by mobilization with soluble gases at ambient reservoir temperature conditions. Experiments were done using carbon dioxide and ethane gases at ～ 20°C to recover Athabasca bitumen from a scaled reservoir model. Thermal gravity drainage theory has been modified for the mass transfer case. The measured drainage rates were higher than those predicted by the model using molecular diffusivity data but fit the model better using an increased effective diffusivity. Lateral dispersion theory does not predict the high measured effective diffusivities. A preliminary economic evaluation of field production indicates potential application to recovery of Lloydminster heavy oil.     

特超稠油开发技术分析

特稠油和超稠油油由于极高的粘度导致开发的难度大大增加。本文在系统调研目前国内外特超稠开发技术的基础上,总结了六种最有潜力的技术并分别进行了分析评价,即水平裂缝辅助蒸汽驱技术、蒸汽加溶剂技术、重力辅助火烧油层技术、水平井火烧油层、水平井蒸汽辅助重力泄油、水平井注气体溶剂萃取技术、出砂冷采技术。     

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。     

聚合物溶液的弹性对残余油滴变形的影响

针对亲油岩石水驱后残余油膜的存在形式及聚合物溶液的粘弹特性,选取上随体Maxwell本构方程。使用计算流体软件Polyflow对模型进行数值分析,分析聚合物溶液弹性对残余油滴的变形影响。     

SIMULTANEOUS HEAT AND FLUID FLOW IN POROUS MEDIA: CASE STUDY: STEAM INJECTION FOR TERTIARY OIL RECOVERY

Heat transfer and fluid flow in porous media occur simultaneously in thermal enhanced oil recovery and significantly increase the rate of energy transfer. The purpose of this investigation was to take advantage of such contemporary transfers and to study heavy oil recovery efficiency using hot-water flooding, cold-water flooding, and steam injection into porous media. A set of multistage laboratory tests was performed to find the temperature profile during steam injection as a means of tertiary oil recovery. Sand-packed models were utilized to investigate the oil recovery efficiency during cold and hot water injection as well as steam flooding for both secondary and tertiary oil production stages. An oil bank was formed in steam injection during the tertiary oil recovery from a vertical standing sand-packed model, resulting in very high oil recovery efficiency. Steam injection was found to be very effective, compared to cold- and hot-water flooding, for the recovery of heavy oil. Based on the principles of transport phenomena in porous media, a mathematical model was developed to predict the temperature profile during the steam injection process. Satisfactory agreement is achieved between the temperature profile predicted from the model and the experimental results.     

Performance of polyacrylamide/Cr(III) gel polymer in oil recovery from heterogeneous porous media: An experimental study

Water channeling due to reservoir heterogeneity is an important factor that could decrease the displacement efficiency of a water flooding process. In this study, the ability of polyacrylamide/ chromium acetate system on altering water path in heterogeneous layered media was investigated using glass bead micromodels. After the relevant parameters were optimized, a series of water and gel injection experiments were conducted in glass bead micromodel. The experimental results show that sweep efficiency is basically controlled by gel strength. The gel strength has a minor impact on the oil recovery from the higher permeable zone, whereas the oil recovery from the lower permeable zone is a strong function of gel strength. Gels with F and G strength codes were observed to divert the water path mostly into low permeable layers. Whereas, gels with B strength code or weaker would alter the water path within the higher permeable layers.     

强化泡沫驱配方的研究

泡沫驱在三次采油中有降低原油和水之间的界面张力,提高驱油效率的特性被广泛应用,在三次采油中有明显的优势。实验以Waring Blender法为试验依据,对ZS系列发泡剂驱在45~95℃温度区间下进行检测,通过泡沫半衰期和析液半衰期来衡量泡沫驱的稳定性。通过考察在温度45~95℃区间,加入不同剂量的AMPS对比试验。通过实验得出ZS-52于20℃时,泡沫体积为960 mL,泡沫半衰期为25.7 h,析液半衰期为2.7 h,发泡量优秀,稳定性强。在95℃时,析泡沫半衰期为8.1 h,液半衰期为36 min,在高温下发泡剂的稳定性要好于常见的油田发泡剂。     

SIMULTANEOUS HEAT AND FLUID FLOW IN POROUS MEDIA: CASE STUDY: STEAM INJECTION FOR TERTIARY OIL RECOVERY

Heat transfer and fluid flow in porous media occur simultaneously in thermal enhanced oil recovery and significantly increase the rate of energy transfer. The purpose of this investigation was to take advantage of such contemporary transfers and to study heavy oil recovery efficiency using hot-water flooding, cold-water flooding, and steam injection into porous media. A set of multistage laboratory tests was performed to find the temperature profile during steam injection as a means of tertiary oil recovery. Sand-packed models were utilized to investigate the oil recovery efficiency during cold and hot water injection as well as steam flooding for both secondary and tertiary oil production stages. An oil bank was formed in steam injection during the tertiary oil recovery from a vertical standing sand-packed model, resulting in very high oil recovery efficiency. Steam injection was found to be very effective, compared to cold- and hot-water flooding, for the recovery of heavy oil. Based on the principles of transport phenomena in porous media, a mathematical model was developed to predict the temperature profile during the steam injection process. Satisfactory agreement is achieved between the temperature profile predicted from the model and the experimental results.     

新型弱碱表面活性剂在三次采油中的应用

以α-烯烃为初始原料，经过烷基化，再经磺化、中和研制出了组分相对单一、结构合理的新型弱碱烷基苯磺酸盐表面活性剂。室内评价结果表明，该表面活性剂具有良好的界面活性，配制的复合体系在较宽的表面活性剂浓度和碱浓度范围可与原油形成10^-3mN／m数量级的超低界面张力。同时，该表面活性剂对大庆油田不同区块、不同油层的油水条件表现出了很强的适应性。另外，由于表面活性剂组成较为单一，可大大降低表面活性剂在地层中因吸附滞留而产生的色谱分离效应。室内天然岩心驱油实验表明，三元复合体系平均驱油效率可比水驱提高约20％。所开展的小井距三元复合驱矿场试验，取得了比水驱提高采收率24．66％的显著效果，为三元复合驱技术在大庆油田的工业化推广，特别是在二类油层的应用奠定了坚实基础。     

毛细管效应的作用--浅谈非均质砂岩储层中的水驱效率

由于缺少储层数据,物理过程非常复杂以及传统上采用过于简单的模拟方法等原因,通常忽略了毛细管效应的作用和毛细管带的岩石特性,从而导致了非均质储层中模拟油层波及系数和驱油的不精确性。利用东部某油田的模拟模型来说明渗透范围、岩石湿润性和毛细管压力滞后效应。在不考虑自吸毛细管压力和滞后现象的情况下,采用饱和度端点比例将这些模拟结果与传统模拟方法进行比较。模拟研究结果表明,毛细管效应使得储层中的流体重新分布,油层泄油以及在水驱下产生不同的渗透范围。利用建立起来的模拟方法可以评价和设计现场应用中的周期注水。     

Lab simulation of profile modification and enhanced oil recovery with a quaternary ammonium cationic polymer

Long-term water flooding in oilfield exploitation generally results in a marked increase of interlayer and/or inner-layer heterogeneity of oil reservoirs and premature polymer production in large quantities from flooding reservoirs. This paper presents a novel quaternary ammonium cationic polymer (NCP), which was prepared by using maize starch and (2,3-epoxypropyl)trimethylammonium chloride as raw materials. The effect of NCP on water plugging and profile modificaton after polymer HPAM (partially hydrolyzed polyacrylamide) flooding was evaluated by laboratory simulation tests of enhanced oil recovery. The experimental results indicate that crosslinking gel system formed after HPAM-NCP alternate injection could effectively seal off the high permeability zone to force the successive liquid to flow to mid-low permeability zones and get profile control in depth. In addition, the contact angle measurements reveal that the adsorption of NCP on the montmorillonite changed its surface wettability and enhanced its hydrophilicity, which promoted enhance oil recovery significantly.     

SPH simulation of oil displacement in cavity-fracture structures

This paper presents a study of the immiscible displacement of oil by water in cavity-fracture structures using smoothed particle hydrodynamics (SPH). The surface tension and wetting behavior are incorporated into the equation of motion, and pseudo periodic boundary conditions are applied. As for “middle-fractured” structure, it is found that the ultimate oil recovery is almost determined by the height of fracture regardless of its orientation, and the result compares well with corresponding experiments. Besides, the water-wet wall is favorable to higher oil recovery. A systematic exploration is carried out on “upper-fractured” structure for the feasibility of gravity drainage, where a critical width of fracture is found, beyond which the oil in the cavity can be driven out. The possible development of SPH in this background for large-scale simulation is prospected finally.     

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.     

Surfactant flooding characteristics of dodecyl alkyl sulfate for enhanced oil recovery

Surfactant-enhanced oil recovery is a type of enhanced oil recovery (EOR), a method to produce residual oil by injecting surfactant solution into the reservoir. The application of surfactant EOR requires knowledge of the phase behavior for more efficient production of residual oil.In this study, the relationship between dodecyl alkyl sulfate and some specific crude oils was examined through phase behavior test. It was found that the branched surfactant was more effective than the linear surfactant. The system was stable at salinities <3 wt%. On adding a small amount of co-surfactant, the emulsion activity was increased.The gravity drainage flooding test (GDFT) was performed to determine the potential of dodecyl alkyl sulfate to produce residual oil in porous media. It was found that the solution could be flooded at temperatures of 60 °C or higher. In the core flooding test, injecting one pore volume of 2 wt% surfactant solution with 3 wt% salinity produced 26.6% more oil after water flood. With the addition of only 0.01 wt% co-surfactant, oil production increased by 1.6%. Contrary to the phase behavior test, the linear surfactant produced 1.3% more oil than the branched surfactant in the core flooding test.     

同心圈式超重力旋转床液泛模型

同心圈式超重力旋转床是一种新型超重力旋转床。液泛是超重力旋转床流体力学的重要特征。同心圈式超重力旋转床液体分布器和转子内缘之间的环形空间内的液滴被气体夹带,液滴受到离心力和气体曳力的作用,通过建立微分方程可获得液滴径向速度为零时的液滴运动径向距离。当该径向距离小于环形空间的径向距离,此时产生雾沫夹带液泛。由此建立同心圈式超重力旋转床雾沫夹带液泛模型。实验以空气和水为物系,测定了转子直径为1000 mm、高度为100 mm的同心圈式超重力旋转床在不同转速和表观液速下气体进口和出口之间的气相压降随表观气速的变化。气相压降随表观气速的增大先缓慢增大后快速增大。用表观气速对气相压降求导和目测旋转床中心气体出口处出现大量液体被气体夹带来确定液泛点气速。通过液泛点气速求得雾沫夹带液泛模型的系数k,并对该系数k进行关联。该雾沫夹带液泛模型的计算值和实验值吻合很好,平均偏差为3.1%。该模型优于Sherwood液泛模型,对同心圈式超重力旋转床的工业应用提供了必要的设计依据。