The effect of wettability heterogeneity on capillary pressure and relative permeability

The effect of wettability on fluid flow properties in porous media has been extensively studied, and is still a subject of highly active investigation. Most of the work has focused on cores of homogeneous wettability. Little attention has been paid to wettability heterogeneity effects at the core or pore scale. In a previous paper, we reported on a series of centrifuge experiments performed to study the effect of wettability heterogeneity on capillary pressure. An experimental technique, named cyclic aging, was developed to create regions of different wetting in the same core sample. In this paper, the work is extended to study the effect of wettability heterogeneity on both capillary pressure and relative permeability curves using centrifuge, continuous injection and steady state techniques.The experimental procedure consists of three steps: (1) the core plug is fully saturated with brine and subsequently a drainage experiment is performed targeting an initial oil saturation S_oi, (2) after aging, oil is displaced by water to residual oil saturation S_or, and (3) oil is injected targeting higher initial oil saturation. In the secondary drainage experiment (step 3), oil first displaces water from the pores exposed to crude oil in primary drainage (step 1) and then enters fresh pores not exposed to crude oil before.In our previous study, it was found that wettability heterogeneity caused a step change in capillary pressure which correlated very well with the saturation at which wettability contrast was expected. However, the height of the step could not be explained by wettability contrast and/or water trapping alone. An experimental artifact caused by the centrifuge technique made the step higher than expected. The experimental artifact was the result of the nonuniform saturation profile developed across the core at the end of the centrifuge experiment. In this study, new techniques were used which resulted in a uniform saturation profile along the core sample during the primary drainage experiment. It was found that in this case the step in the capillary pressure is determined by wettability contrast and water trapping. It was also found that the relative permeability curve changes its characteristics when oil accesses the pores not previously exposed to crude oil.The results of this study show that (1) only the part of the pore space exposed to crude oil undergoes wettability changes on both core scale and pore scale, and (2) ignoring wettability heterogeneity can lead to large errors in the estimated two phase flow functions with important consequences with respect to fluid flow in porous media.     

Wettability effects in a sandstone reservoir and outcrop cores from NMR relaxation time distributions

An extensive literature has emerged on the use of nuclear magnetic resonance (NMR) relaxation methods for the determination of various petrophysical properties such as porosity, permeability, initial water saturation and free fluid index. Although observations were first made in the 1950s, relatively few papers have appeared, which use NMR methods to determine the wettability state of a crude oil/brine/rock (COBR) system.Differences in the relaxation time distributions (for both T₁ and T₂) at the various saturation stages in the Amott test cycle provide both qualitative and quantitative information on the wettability state in sandstone samples. Two particularly convenient ways of plotting our results are proposed based on: (a) the arithmetic mean relaxation time differences given by ΔT₁=T₁ at S_or−T₁ at S_wi and ΔT₂=T₂ at S_or−T₂ at S_wi; and, (b) the arithmetic mean relaxation time ratios given by T₁ at S_wi/T₁ at S_or and T₂ at S_wi/T₂ at S_or. In each case, these quantities are plotted against the Amott–Harvey (AH) index and good linear relationships are found. We propose measuring the relaxation times at the S_wi and S_or stages of a flood cycle and plotting the results in this way as the basis of quantitative NMR-based tests to characterise rock wettability. We find that both the T₁ and T₂ relaxation time data correlate with the wettability condition of the system although the T₁ plots give rather better wettability indicators. This implies that both relaxation times carry broadly similar information on wettability. Although the correlations are somewhat weaker for T₂, there is some potential for indicating wettability alteration using T₂ distributions obtained from downhole NMR logging tools.Comparing the corresponding T₁ and T₂ cumulative curves before and after ageing indicates that wetting alteration first takes place in the larger pores, while the smaller pores appear to remain water-wet. The number of wetting altered pores (from water-wet→weakly water-wet→oil-wet) increases with the increase in ageing time, indicating that the samples studied here are showing mixed wettability behaviour on ageing.     

NMR wettability indices: Effect of OBM on wettability and NMR responses

Wettability and NMR surface relaxation are related to each other. Wettability controls the fluid distribution in porous media. NMR surface relaxation dictates that the fluid in contact with the mineral surface has a relaxation time shorter than its bulk value. In this study, first, the nature of wettability effect on NMR responses was demonstrated by a parameter ρ_{2, eff}, the effective surface relaxivity. Quantitative changes of ρ_{2, eff} of water or oil for unconsolidated silica flour and calcite were shown to be consistent with the expected wettability alteration based on the contact angle measurements. Based on the concept of effective surface relaxivity, a novel NMR model was then proposed to quantify rock wettability by two NMR wettability indices from either water or oil responses. This model was tested with water/oil partially saturated Berea cores at different wettability conditions. Correlations show that both NMR indices agree well with the Amott–Harvey wettability index, suggesting that quantitative information of reservoir rock wettability can be gained from NMR measurements. Finally, the effect of oil base mud (OBM) surfactants on wettability alteration and NMR responses was systematically investigated with Berea cores. Results show that the originally strongly water-wet Berea cores are altered to be intermediate-wet or oil-wet by OBM surfactants. As a result, the irreducible water saturation from NMR interpretation assuming water-wetness when wettability alteration occurs generally underestimates the measured value. The magnitude of underestimation correlates well with the Amott–Harvey wettability index.     

Simulation of Wettability Alteration by Low-Salinity Water Injection in Waterflooded Carbonate Cores

Low-salinity water injection is an emerging improved oil recovery technique due to its simplicity compared to other water based improved oil recovery methods. In this study, the wettability alteration option in the authors’ in-house simulator is used to history match and provide some insights in different seawater dilution cycles based on recently published corefloods. Two newly proposed methodologies to model dilution cycles are employed. The authors successfully modeled the experiments enhancing the wettability alteration model in the simulator using two different scaling factors. The study also revealed that the process is more sensitive to oil relative permeability compared to that of the water phase. A linear interpolation model for residual oil saturation (S_or) was proposed.     

Investigation of supercritical carbon dioxide, aspheltenic crude oil, and formation brine interactions in carbonate formations

Asphaltene precipitation and rock dissolution can significantly hinder the success of carbon dioxide flooding of asphaltenic crude oil in carbonate heterogeneous formations. It is essential during CO₂ flooding when both processes exist to study separately the effect of each phenomenon on the flooding process. Ten core flooding experiments under similar reservoir conditions of 4000 psia pressure and 250 °F temperature were conducted to evaluate each phenomenon separately. Actual rock cores representing different areas of carbonate oil field saturated with actual fluids of filtrated brine and asphaltenic crude oil were used to evaluate the interaction between supercritical (SC)-CO₂, carbonate rock, and its contained fluid. Asphaltene content of the produced crude oil, water and mineralogical rock analyses, and scanning electron microscopic (SEM) photos of rock pores were performed to evaluate the effect of supercritical (SC)-CO₂ flood on the permeability and mineralogical variation characteristics of the limestone cores. Results indicated that calcite dissolution and/or precipitation is the major reason for permeability improvement and/or impairment. It is also proven that the amount of permeability damage depends on the fabric of the rocks, salinity of the brine, and initial core permeability. The results also indicated that CO₂ injection in fresh water saturated carbonate rock led to complete collapse of that rock. It is recommended that fluid assessment should be conducted to the different areas of the field.     

弱凝胶对油水相对渗透率的影响

在凝胶处理后,油/水相相对渗透率均大幅度下降,可动饱和度范围明显缩小,弱凝胶的易屈服性导致渗透率随流速增加而上升.凝胶处理使油/水相渗透率产生不均衡减少是由于油在通过凝胶时部分残余油占据的孔隙形成了新的流动通道;但水驱时,由于油/水界面张力较高,残余油形成的大部分通道关闭.所以,在同样的驱动力下油/水通过凝胶处理后的含油地层时,油相渗透率高于水相渗透率.     

孤东油田七区西相对渗透率曲线研究

油水相对渗透率曲线综合反映了互不相溶的油水两相在不同含水饱和度下渗流规律的变化,是油田开发设计中产能预测的基础资料;而不同开采阶段取心岩样相渗曲线的变化,能够反映储集层结构的变化,研究这一变化可为油田剩余油挖潜提供理论依据。孤东油田七区西馆陶组上段取心井资料表明,随着水驱过程的深入,油水相对渗透率曲线的特征值发生了变化,束缚水饱和度和残余油饱和度减小、等渗点含水饱和度及残余油饱和度下的水相渗透率增大,反映出油层孔隙度增大、黏土矿物减少、孔隙比表面积减少、孔隙表面更亲水以及水驱结束后储集层的综合渗流能力有所增加等特征。不同阶段相渗参数分析表明,油田进入高含水期后,孔隙度对渗透率、渗透率对残余油饱和度、两相共渗区、驱油效率等参数的影响作用相对增大。研究结果认为,该油田三次采油应立足于改善储集层结构和驱油剖面,减少孔间矛盾,提高驱油效率。     

CO2启动盲端孔隙残余油的微观特征

低渗透油藏中存在大量的盲端孔隙,其中赋存的原油通常难以被水驱启动,成为水驱残余油的一种表现形式。建立玻璃刻蚀微观盲端孔隙模型,饱和油后开展室内实验模拟水驱、CO2非混相驱和CO2混相驱等开发过程,利用微观可视系统观测盲端孔隙中残余油在各种驱替方式下的启动特征。实验结果显示,水驱仅可以进入盲端孔隙较浅的区域,难以启动残余油;CO2非混相驱可深入盲端孔隙,部分残余油被启动,并沿内壁流出,进入主通道;CO2混相驱则可以驱替盲端孔隙深部的残余油,且随着CO2注入孔隙体积倍数的增大,基本可以将盲端孔隙中的原油驱替干净。分析认为,水驱仅依靠压力变化及流体弹性启动极少量的盲端孔隙残余油,而超临界CO2则可以不停地与残余油发生组分交换,通过流体间的传质作用进入盲端孔隙,从而启动大量残余油。因此,超临界CO2不仅对常规驱替介质波及的可流动孔隙具有较高的驱油效率,还可以启动盲端孔隙中的残余油,降低残余油饱和度,提高采收率。     

Study on the blockage in pores due to asphaltene precipitation during different CO2 flooding schemes with NMR technique

CO₂ flooding is an effective way in the tertiary oil recovery. While asphaltene often precipitates from the crude oil during the CO₂ flooding, and the mechanisms of blockage resulting from asphaltene precipitation is still unclear in different CO₂ flooding schemes. In this work, pure-CO₂ flooding, water-alternating-CO₂ flooding (WAG), and CO₂-foam flooding were applied to conduct the core-flooding experiments. Then, as for each flooding scheme, we quantitatively investigated the blockage degree in different pores due to asphaltene precipitation with nuclear magnetic resonance (NMR) technique. Tests results show that CO₂-foam flooding has a relatively higher blockage degree both in the smaller pores and the larger pores than WAG and pure-CO₂ flooding. Although pure-CO₂ flooding has the least asphaltene precipitation and blockage degree among three flooding schemes, its oil recovery degree is far less than the other two flooding schemes. Compared with pure-CO₂ flooding and CO₂-foam flooding, WAG flooding has the highest oil recovery and an acceptable asphaltene precipitation.     

物理模拟研究剩余油微观分布

通过微观透明模型研究了注水开发剩余油形成的微观形态,研究了水驱、聚合物驱和弱凝胶调驱等驱油方式下剩余油的形成过程、微观分布规律和影响剩余油分布的主、次要因素。把剩余油分为可动剩余油、条件可动剩余油和不可动剩余油。研究得出,储集层岩石的非均质性是剩余油形成的主要原因。水驱剩余油主要分布在注入水未波及区、亲油岩石表面、死孔隙、狭小孔隙或低渗储集层以及部分堵塞的孔隙中;聚合物驱后的剩余油主要是死孔隙中的不可动油和小孔隙以及吸附在亲油岩石表面的条件可动油;弱凝胶调驱后的剩余油主要是死孔隙中的不可动油和吸附在岩石表面的条件可动油。     

疏松砂岩油藏冷冻岩心与常规岩心相渗曲线研究

为了更好地评价疏松砂岩油藏的水驱开发特点,针对实际油藏地质和流体性质特征,用室内水驱油非稳态法,研究近似油藏条件下冷冻岩心与常规岩心的油水相渗曲线,并进行对比分析。在数据处理过程中,利用JBN经验公式法进行计算,采用对数函数对其进行拟合与回归,最后绘出油水相渗曲线,并作为判断水驱效果的依据。结果表明,水驱后冷冻岩心的残余油饱和度平均为29%,残余油饱和度对应的水相相对渗透率为0.32,驱油效率平均为52%;常规岩心的残余油饱和度平均为30%,残余油饱和度对应的水相相对渗透率为0.30,驱油效率平均为52%。同一含水饱和度所对应的冷冻岩心,其水相相对渗透率高于常规岩心所对应的水相相对渗透率,但常规岩心见水时间早于冷冻岩心,且含水上升较快。冷冻岩心的最终水驱油效率和无水采收率均高于常规岩心。     

不同驱油体系在贝雷岩心中的驱替特征

为了保持室内岩心驱油实验中孔隙结构对驱替剂驱油效果的影响与实际砂岩油层孔隙结构的影响一致,使用气测渗透率300×10-3μm2的贝雷、人造、天然均质岩心进行常规压汞实验和驱油实验.研究了不同类型岩心孔隙结构差异及其对驱油效果的影响,分析了不同驱油体系在贝雷岩心中的采收率及注入压力变化.实验结果表明:贝雷岩心与天然岩心在孔喉结构上有一定的相似性,能够充分体现各种体系的驱油效果;在贝雷岩心中,保持体系黏度、表面活性剂质量浓度相同条件下,化学驱采收率由高到低顺序为弱碱三元体系、强碱三元体系、聚合物—甜菜碱表活剂体系、聚合物体系,三元复合驱后续水驱阶段采出的油量对化学驱采收率的贡献较大,驱油过程中体系是否发生乳化对驱油体系的驱油效果存在明显影响;聚合物溶液和三元体系驱替过程中的压力存在明显的不同,聚驱过程中的主要特点是注化学剂过程结束后压力快速下降,复合驱压力变化曲线主要特点是注化学剂结束后水驱阶段压力先上升后下降,乳化—捕集机理是造成注入压力曲线形态差异的主要原因.     

Pore-scale investigation of residual oil displacement in surfactant–polymer flooding using nuclear magnetic resonance experiments

Research on the Gangxi III area in the Dagang Oilfield shows that there was still a significant amount of oil remaining in oil reservoirs after many years of polymer flooding.This is a potential target for enhanced oil recovery(EOR).Surfactant–polymer(SP) flooding is an effective chemical EOR method for mobilizing residual oil and improving displacement efficiency macroscopically,but the microscopic oil displacement efficiency in pores of different sizes is unclear.Nuclear magnetic resonance(NMR) is an efficient method for quantifying oil saturation in the rock matrix and analyzing pore structures.In this paper,the threshold values of different pore sizes were established from the relationship between mercury injection curves and NMR T2 spectrums.The distribution and migration of residual oil in different flooding processes was evaluated by quantitatively analyzing the change of the relaxation time.The oil displaced from pores of different sizes after the water flood,polymer flood,and the SP flood was calculated,respectively.Experimental results indicate that(1) the residual oil in medium pores contributed the most to the incremental oil recovery for the SP flood,ranging from 40 % to 49 %,and small pores usually contributed \30 %;(2) the residual oil after the SP flood was mainly distributed in small and medium pores;the residual oil in medium pores accounted for 47.3 %–54.7 %,while that trapped in small pores was 25.7 %–42.5 %.The residual oil in small and medium pores was the main target for EOR after the SP flood in oilfields.     

Prediction of wettability variation and its impact on flow using pore- to reservoir-scale simulations

We describe a pore- to reservoir-scale investigation of wettability variation and its impact on waterflooding. We use a three-dimensional pore-scale network model of a Berea sandstone to predict relative permeability and capillary pressure hysteresis. We successfully predict experimentally measured relative permeability data for the water-wet case, and demonstrate that the model captures experimentally observed trends in waterflood recovery for mixed-wet media. We then focus upon the effect of variations in initial water saturation associated with capillary rise above the oil–water contact (OWC). This may lead to wettability variations with height because the number of pore-walls which may be rendered oil-wet during primary drainage, increases as the oil saturation increases. We investigate empirical hysteresis models in which scanning curves are used to connect bounding drainage and waterflood curves for a given initial water saturation, and find that if wettability varies with initial water saturation, then the scanning water relative permeability curves predicted by the empirical model are significantly higher than those predicted by the network model. We then use a conventional simulator, in conjunction with the relative permeability curves obtained from the network and empirical models, to investigate the reservoir-scale impact of wettability variations on waterflooding. If the wettability varies with height above the OWC, we find that using the network model to generate scanning relative permeability curves yields a significantly higher recovery than using empirical models or assuming that the reservoir is uniformly oil-wet or water-wet. This is because the scanning water curves are generally low (characteristic of water-wet media), yet the residual oil saturation is also low (characteristic of oil-wet media). Our aim is to demonstrate that network models of real rocks may be used as a tool to predict wettability variations and their impact on field-scale flow.     

聚合物驱后多元调驱体系提高采收率研究

根据聚合物驱后提高采收率的需要,筛选了多元调驱体系的凝胶颗粒类型、交联剂最优浓度和洗油剂最优浓度,分别考察了单元注入体系(50 mg/L或100 mg/L交联剂、2000 mg/L阳离子凝胶微球,注入体积1 PV),二元注入体系(100 mg/L交联剂+2000 mg/L阳离子凝胶微球,注入体积1 PV)和三元注入体系(0.4 PV×2000mg/L阳离子凝胶微球+0.3 PV×100 mg/L交联剂+0.4 PV×2000 mg/L高效洗油剂)的调剖效果。实验结果表明:二元注入体系转水驱突破压力为3 MPa左右,而且压力整体波动范围和波动幅度都明显高出单元注入体系的,这说明二元注入体系调剖效果比单元注入体系的好;在水驱采收率39.65%、聚合物驱提高采收率18.38%的基础上,三元注入体系提高采收率22.82%;水驱和聚合物驱阶段注入压力较低,凝胶微球注入后压力迅速上升,交联剂的注入保持了压力,高效洗油剂驱使压力进一步上升,转后续水驱后压力下降并稳定在2 MPa左右;与二元注入体系相比,三元注入体系的后续水驱压力明显降低,这保证了在不影响调驱效果的同时还能降低后续水驱压力,因此多元注入体系具有更好的实际应用价值。图5表3参9     

低渗透油藏复合生物酶驱油室内实验研究

延长油田属于典型的低渗透油藏,一次开采采收率低,水驱含水率上升快,整体驱油效果差。生物酶是一种无污染水溶性制剂,可有效注入地层孔隙中,改变岩石润湿性,剥蚀岩石颗粒表面原油,降低残余油饱和度,从而提高原油采收率。利用一维填砂物理模型和岩心流动实验,对SUN型复合生物酶溶液的驱油效果进行了室内实验及评价。结果表明:当SUN型复合生物酶溶液的注入体积分数约为3%,注入量约为0.4倍孔隙体积时,驱油效果最佳,并且对于低渗透岩心的驱油效果也相当明显,驱油效率提高值最大可达11.4%,表明SUN型复合生物酶驱油剂对低—特低渗透油藏具有较强的适应性。     

聚合物驱前后储层含油性与渗透性变化特征试验研究

注入聚合物溶液后,储层的含油性和渗透性将发生相应的变化。通过聚合物驱岩心试验,对比分析了注聚合物前后岩心的束缚水饱和度、残余油饱和度、绝对渗透率和相对渗透率的变化特征。试验结果表明,和注聚合物前相比,注聚合物后岩心的束缚水饱和度增大,残余油饱和度明显减小,而岩心的绝对渗透率变化不大,聚合物/油体系的相对渗透率曲线除具有水湿岩心相渗曲线的典型特征外,其水相的相渗曲线及其端点值明显低于常规油/水体系的相渗曲线,而且降低幅度随束缚水饱和度增大而增大,但其油相相渗曲线与常规油/水体系的油相相渗曲线的差距很小。     

致密油藏活性水采油机理

注活性水相较于注水有诸多优势,在特低渗、超低渗油藏的实际开发中效果较好,因此可以借鉴到致密油藏的开发上。针对鄂尔多斯盆地X区块致密油储层,选取不同渗透率的岩心进行注水和注活性水驱油物理模拟实验,结合核磁共振技术,分析致密油岩心的微观孔隙结构、可动流体饱和度以及不同渗透率等级岩心的采出程度、残余油分布等。研究表明:大部分致密油油藏的孔隙为亚微米、微纳米孔,可动流体主要赋存于大于1μm的孔隙中;注活性水效果好于常规水驱,注活性水能够有效地动用微纳米孔中的原油;渗透率越低注活性水的驱油效果越明显,对于渗透率低于0.6×10~(-3)μm的致密油藏,建议采用注活性水开发。     

特低渗砂岩油藏CO2-低界面张力黏弹流体协同驱油机理研究

目的特低渗油藏储层物性差、层间非均质性强,造成CO₂驱易发生气窜,提高采收率效果欠佳,其中,CO₂水气交替驱作为结合CO₂驱和水驱优势的方法,具有较高的适用性。为进一步改善CO₂-水交替驱的开发效果,开展了CO₂-低界面张力黏弹流体协同驱油研究。 方法通过界面张力和润湿性能测试评价低界面张力黏弹流体基本性能,并利用微观可视化驱油实验及岩心驱油实验等,探究了不同驱替方式的驱油效果和CO₂-低界面张力黏弹流体协同驱油过程中二者之间的“协同作用”机理。 结果低界面张力黏弹流体具备良好的界面活性和改变岩石表面润湿性能力,水驱后开展CO₂驱、低界面张力黏弹流体驱、CO₂-低界面张力黏弹流体交替协同驱,采收率可在水驱基础上分别提高0.91%、10.66%、16.25%,其提高采收率机理包括降低界面张力、改善流度比、改变岩石表面润湿性及乳化作用的协同效应等。 结论CO₂-低界面张力黏弹流体协同驱既可有效增强非均质特低渗砂岩油藏注CO₂过程中气体流动性控制,又能够降低CO₂萃取轻烃导致重质组分沉积的影响,具有协同增效作用。      

PERFORMANCE AND PROPERTIES OF KUSP1–BORIC ACID GEL SYSTEM FOR PERMEABILITY MODIFICATION PURPOSES

ABSTRACT

Blocking high permeability zones of reservoirs by hydrogels, and diverting the injected fluid towards the unswept zones of the reservoir is a promising method for improving the overall oil recovery in waterflooding and carbon dioxide flooding processes. A polymer gel treatment typically involves the injection of a solution of a medium to high molecular weight polymer and crosslinking agents into the high permeability zones or fractures. The polymer reacts with the crosslinker to form a three-dimensional gel network. KUSP1 biopolymer in sodium hydroxide solution produces a delayed gel system with orthoboric acid. The gelation time varies depending on the concentration of the orthoboric acid and temperature. Syneresis of this gel was studied in bottle tests as well as in the porous media. Samples of KUSP1–boric acid gel lost more than 80% of their initial volume in bottle tests after 250 h. Also, it was observed that this gel, when placed in a sandpack, lost up to about 50% of its initial volume. However, the high values of syneresis did not have a severe effect on the performance of the gel in porous media. KUSP1–boric acid gel was tested for reducing permeability to carbon dioxide and water in a series of tests conducted in a Berea sandstone core. It reduced the carbon dioxide permeability from 164 to 26 md and brine permeability from 420 to 90 md.