The surface wettability of brine in a tight oil reservoir

Based on DSA100 instrumentation, the interactions between the chemical groups on the rock surface and brine were analyzed to study the abilities and microscopic mechanisms on reservoir characteristics of wettability controlled by Na⁺, Ca²⁺and Mn²⁺. The results show that that in the same solution, static and dynamic angle of each ions are consistent. When the concentration of CaCl₂ solution is more than 0.5 mol/L, the contact angle will change greatly. Ca²⁺, Mn²⁺ can change the structural characteristics of tight reservoirs. This provides a theoretical basis for our study of low salinity water flooding and recovery ratio.     

Injection of seawater and mixtures with produced water into North Sea chalk formation: Impact of fluid–rock interactions on wettability and scale formation

Seawater has been injected into high temperature and natural fractured North Sea chalk reservoirs to improve oil recovery with great success. Previous studies have shown that seawater will improve the water wetness and cause enhanced compaction of the matrix. The composition of the produced water will be quite similar to initial formation water at the start of the water injection. The formation water contains various amounts of divalent cations like Mg²⁺, Ca²⁺, Sr²⁺, and Ba²⁺. Later on, the composition will change due to the interaction between seawater and the chalk formation and some mixing with formation water. The fluid–rock interaction will involve dissolution of CaCO₃, substitution of Ca²⁺ by Mg²⁺ at the chalk surface, precipitation of CaSO₄, SrSO₄ and BaSO₄ depending on the reservoir temperature. Because of environmental reasons, it is desirable to re-inject produced water together with seawater. In the forthcoming research, we will study experimentally the effect of this re-injection on oil recovery and chalk compaction by using mixtures of produced water and seawater as injection fluid. Based on model studies using the OLI software package, the compatibility of mixtures of produced water and seawater has been studied at different temperatures by looking at the precipitation of CaSO₄, SrSO₄ and BaSO₄. Also the impact of changes in the concentrations of Ca²⁺ and Mg²⁺ due to surface substitution is modelled. The results are discussed in terms of possible scale formation in the producer and injector. In addition, actual chemical equilibrium reactions in the chalk matrix are discussed in relation to variation in temperature during continuous injection of seawater. Special focus is made on wettability modification, irreversible thermodynamics, and impact on the mechanical strength of the chalk matrix.     

Geochemical evaluation of low salinity hot water injection to enhance heavy oil recovery from carbonate reservoirs

Although low salinity water injection (LSWI) has recovered residual oil after the conventional waterflood, highly viscous oil has remained in heavy oil reservoirs. Hot water injection is an economic and practical method to improve oil mobility for viscous oil reservoirs. It potentially controls temperature-dependent geochemical reactions underlying the LSWI mechanism and oil viscosity. Therefore, this study has modeled and evaluated a hybrid process of low salinity hot water injection (hot LSWI) to quantify synergistic effects in heavy oil reservoirs. In comparison to seawater injection (SWI) and LSWI, hot LSWI results in more cation ion-exchange (Ca²⁺ and Mg²⁺) and more wettability modification. Hot LSWI also reduces oil viscosity. In core-scaled systems, it increases oil recovery by 21% and 6% over SWI and LSWI. In a pilotscaled reservoir, it produces additional oil by 6% and 3% over SWI and LSWI. Probabilistic forecasting with uncertainty assessment further evaluates the feasibility of hot LSWI to consider uncertainty in the pilot-scaled reservoir and observes enhanced heavy oil production. This study confirms the viability of hot LSWI due to synergistic effects including enhanced wettability modification and oil viscosity reduction effects.     

致密油充注过程中储层润湿性变化对含油性影响——以川中侏罗系致密油为例

以四川盆地川中侏罗系致密油储层岩心样品为例,开展了致密油微观充注物理模拟实验。实验模型采用砂岩薄片模型(尺寸为2.5 cm×2.5 cm,厚度约0.6 mm),将实验用油注入模型引槽中,压力由小到大逐步增加至每个模型出口端只出油不出水为止,观测渗流特征并计算含油饱和度。实验结果显示,充注前样品束缚水饱和度与充注后含油饱和度总和大于100%,基于核磁共振法对储层束缚水等流体饱和度与储层润湿性的分析,提出了充注前后储层润湿性的改变(水润湿转变为油润湿)使得最终含油饱和度高于被驱替的动水饱和度。致密油运聚过程中储层润湿性改变抵消了致密油储层高束缚水饱和度对致密油含油性的抑制作用,利于致密油运聚,是致密油成藏含油饱和度提高的重要原因。     

基于孔隙矿物和流体分布的致密油储层润湿性研究

基于孔隙周围矿物分布和不同大小孔隙内流体分布特征研究致密油储层岩石整体及不同大小孔隙的润湿性。首先基于扫描电镜实验研究了致密油储层中不同尺寸孔喉周围的矿物分布特征,其次借助自发渗吸和核磁共振实验研究了不同流体进入致密油储层孔隙后的分布状态,最后基于孔隙周围的矿物分布特征,通过岩石分别在水相和油相中自吸后的自吸曲线和核磁T₂谱分布判断岩石整体及孔喉润湿性。研究结果表明,目标岩心大孔隙周围以碳酸盐岩矿物为主,小孔隙周围以黏土矿物和硅酸盐矿物为主;自发渗吸和核磁实验相互验证显示岩石整体偏水湿,具体为大孔隙偏油湿,小孔隙偏水湿。该研究为评价致密油岩石整体及不同大小孔隙的润湿性提供了新思路。     

An investigation of the effect of wettability on NMR characteristics of sandstone rock and fluid systems

Predicting reservoir wettability and its effect on fluid distribution and hydrocarbon recovery remains one of the major challenges in reservoir evaluation and engineering. Current laboratory based techniques require the use of rock–fluid systems that are representative of in situ reservoir wettability and preferably under reservoir conditions of pressure and temperature. However, the estimation of reservoir wettability is difficult to obtain from most laboratory experiments. In theory, it should be possible to determine the wettability of reservoir rock–fluid systems by nuclear magnetic resonance (NMR) due to the surface-sensitive nature of NMR relaxation measurements. Thus, NMR logs should in principle be able to give an indication of reservoir wettability, however, as yet there is no proven model to relate reservoir wettability to NMR measurements. Laboratory NMR measurements in representative and well-characterised rock–fluid systems are crucial to interpret NMR log data.A series of systematic laboratory experiments were designed using a range of sandstone core plugs with the aim of investigating the feasibility of using NMR measurements as a means to determine wettability. NMR T₂ spectrum measurements were performed in reservoir core plugs at different saturations and wettability states. The samples were first cleaned by hot solvent extraction, then saturated with brine and a drainage/imbibition cycle performed. At the lowest brine saturation the same samples were aged in crude oil and a further drainage/imbibition cycle performed. NMR transverse relaxation time, T₂, was measured on fully saturated samples, at residual saturations and some intermediate saturation values. The wettability of the samples is evaluated using the Archie's saturation exponent and by Amott-Harvey wettability index.The wettability of the cores studied ranged from mixed-wet to oil-wet. The NMR T₂ results for cleaned and aged reservoir core plugs, containing oil and water, show that fluid distribution and wettability can be deduced from such measurements. The results on aged core plugs suggest that the oil occupies a wide range of pore sizes and is in contact with the pore walls. The results presented in the paper suggest that NMR T₂ relaxation has the potential to be an alternative technique to evaluate rock wettability in the laboratory and in the reservoir.     

Efficiency of enhanced oil recovery by injection of low-salinity water in barium-containing carbonate reservoirs

When low-salinity water containing sulfate ions is injected into carbonate reservoirs, rock dissolution and in situ precipitation occur, altering rock permeability and wettability. Particularly, when barium ions are present in formation water, they react chemically with \({\text{SO}}_{4}^{2 - }\), and BaSO₄ is precipitated. These reactions can cause a serious impact on the efficiency of enhanced oil recovery (EOR). Therefore, the main purpose of this study was to identify EOR efficiency induced by low-salinity waterflooding (LSWF) when Ba²⁺ is present in carbonate reservoirs. From the experimental results, it was confirmed that the permeability calculated by the measured pressure difference was improved because of rock dissolution predominating over in situ precipitation for the case of low Ba²⁺ concentrations. In the analysis of wettability alteration through the measurements of relative permeabilities before and after LSWF, the higher Ba²⁺ concentration case consumed more \({\text{SO}}_{4}^{2 - }\) in precipitating the BaSO₄, resulting in weaker wettability alteration due to the reduction of sulfate activity. These phenomena ultimately influenced EOR efficiency, i.e., the oil recovery was greater for the lower Ba²⁺ concentration.     

致密油藏混合润湿性测试新方法及其应用

致密油储层矿物成分的复杂性和分布的随机性决定了岩石孔隙表面的润湿性是不均匀的。将致密油藏物理模拟实验方法和核磁共振技术相结合,提出了致密油藏混合润湿性测试新方法。在此基础上,确定出混合润湿指数的分类界限,探讨了致密油藏岩心原始润湿性测量方法。研究表明:致密油岩心经过洗油后,所测试的混合润湿指数大多数位于0~0.4,处于弱亲水;而未洗油的新鲜岩样,同一块致密油岩心所测试初始状态下的混合润湿指数要大于原始状态下的混合润湿指数;所测试的致密油岩心在原始地层条件下大部分呈弱亲油,少部分呈弱亲水。这种测试新方法可以对致密油藏有效开发提供可靠的技术参数。     

碳酸盐岩油藏低矿化度水驱作用机理实验

碳酸盐岩油藏低矿化度水驱应用潜力巨大,为了更好地推广其矿场应用而针对性开展作用机理的实验研究。首先,岩心驱替实验研究注入水矿化度和关键离子组成对采收率的影响;而后,润湿角测定实验分析注入水矿化度和关键离子组成对碳酸盐岩表面润湿性的影响;最终,根据实验结果建立碳酸盐岩油藏低矿化度水驱作用机理。研究发现：低矿化度水驱能有效改变碳酸盐岩表面润湿性进而提高油藏采收率,存在最优矿化度使得碳酸盐岩表面润湿性变化最大、采收率最高;Mg²⁺和SO₄^2-对碳酸盐岩表面润湿性和原油采收率的影响效果不同;随着溶液中Mg²⁺浓度升高,碳酸盐岩表面润湿性变化不断增强、原油采收率不断升高;随着溶液中SO₄^2-浓度增加,碳酸盐岩表面润湿性变化先增强后减弱、原油采收率先增加后稳定。碳酸盐岩油藏低矿化度水驱作用机理在于润湿性的改变：①SO₄^2-吸附在正电性的碳酸盐岩矿物表面,中和表面电荷,促进了Mg²⁺向矿物表面运动;②Mg²⁺与碳酸盐岩矿物表面的Ca²⁺发生取代反应,造成原油组分的解离。     

Wettability Alteration of Low-permeable Carbonate Reservoir Rocks in Presence of Mixed Ionic Surfactants

Abstract

Altering the wettability of the carbonate reservoir rocks from oil-wet to water-wet has figured prominently as one of the enhanced oil recovery methods in recent years. The authors measured the effect of different ionic surfactants on the wettability alteration of the rock, saturated with crude oil, and the consequent improvement in oil production was investigated by spontaneous imbibitions of solutions containing cationic, anionic, and cationic-anionic surfactant mixtures. A very low-permeable carbonate rock from one of the Iranian oil reservoirs was selected for this study. The results of imbibition tests were furthermore supported by measuring IFT, taking pictures of producing oil drops from different exterior core plug surfaces and also observing the distribution of the remaining oil in cores at the end of experiments. The results show that cationic surfactants at concentrations higher than CMC can cause a remarkable oil production through alteration of wettability and, moreover, the extent of oil production increases with temperature. In contrast, it is observed that the anionic surfactants are not able to change the wettability of an oil-wet surface and their combination with the cationic type would reduce the oil production potential of cationic surfactants.     

Use of natural geochemical tracers to improve reservoir simulation models

This article introduces a methodology for integrating geochemical data in reservoir simulations to improve hydrocarbon reservoir models. The method exploits routine measurements of naturally existing inorganic ion concentration in hydrocarbon reservoir production wells, and uses the ions as non-partitioning water tracers. The methodology is demonstrated on a North Sea field case, using the field's reservoir model, together with geochemical information (SO₄²⁻, Mg²⁺, K⁺, Ba²⁺, Sr²⁺, Ca²⁺ and Cl⁻ concentrations) from the field's producers. Based on the dataset, some of the ions are shown to behave almost as ideal seawater tracers, i.e. without sorption to the matrix, ion exchange with the matrix or scale formation with other ions in the formation water. Moreover, the dataset shows that ion concentrations in pure formation water vary according to formation. This information can be used to allocate produced water to specific water-producing zones in commingled production. Based on an evaluation of the available data, one inorganic component, SO₄²⁻, is used as a natural seawater tracer. Introducing SO₄²⁻ as a natural tracer in a tracer simulation has revealed a potential for improvements of the reservoir model. By tracking the injected seawater it was possible to identify underestimated fault lengths in the reservoir model. The demonstration confirms that geochemical data are valuable additional information for reservoir characterization, and shows that integration of geochemical data into reservoir simulation procedures can improve reservoir simulation models.     

降低启动压力的表面活性剂体系在朝阳沟油田的应用

针对朝阳沟低渗透油田注水过程中注水压力上升较快、欠注严重的问题,进行了朝阳沟油田降压增注表面活性剂体系的筛选工作,最终确定表面活性剂体系的配方为0.2%石油磺酸盐类表面活性剂T702-40^#+0.5%Na₂CO₃。实验结果表明,该表面活性剂体系与原油间平衡界面张力能够达到2×10^-2mN/m,耐温、抗盐性好,与朝阳沟油田注入水和地层水配伍性好,能够使岩石的润湿性发生反转,比水驱提高采收率5%左右。该表面活性剂体系驱替计算得出的可流动渗透率值约比水驱可流动渗透率值大15%,具有明显的降低启动压力的作用,并进行了表面活性剂体系降低启动压力的机理分析。朝阳沟油田朝82-152井区矿场试验结果表明,该表面活性剂体系能够降低启动压力,使油层吸水能力提高,使低渗透储层动用比例提高,7口油井累积增油1768t。     

源-储分离型凝灰岩致密油藏形成机理与成藏模式

由于致密油藏储层致密,原油充注的阻力较大,烃源岩的高剩余压力是致密油藏原油充注的主要动力,因此,致密油藏一般为源内型和近源型。与以往已发现的大多数致密油藏不同,三塘湖盆地马朗凹陷条湖组凝灰岩致密油藏属于源-储分离型致密油藏。通过油源对比、压汞、岩石润湿性和油水驱替实验等方法,结合地质条件综合分析了条湖组凝灰岩致密油藏的类型、原油的来源、原油充注机理和成藏模式。研究表明：凝灰岩致密油藏的原油主要来自下伏芦草沟组二段烃源岩,属于源-储分离型致密油藏;条湖组凝灰岩中沉积有机质生成原油的极性组分优先吸附在孔隙表面,使得岩石润湿性转为偏亲油,加之凝灰岩孔喉比小,从而导致油驱水启动压力梯度较小,这是远源的凝灰岩致密储层内原油能够得以充注成藏和富集的主要原因。凝灰岩内致密油的成藏与富集主要受控于凝灰岩储层质量和芦草沟组二段良好的排烃条件及断裂-裂缝输导体系,其成藏模式为：“自源润湿、它源成藏、断-缝输导、多点充注、有效凝灰岩储层大面积富集”。     

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.     

Geochemical studies of the Silurian oil reservoir in the Well Shun-9 prospect area, Tarim Basin, NW China

Commercial oil flow has been obtained from the sandstone reservoir of the Lower Silurian Kelpintag Formation in the Well Shun-9 prospect area.In the present studies,10 Silurian oil and oil sand samples from six wells in the area were analyzed for their molecular and carbon isotopic compositions,oil alteration（biodegradation）,oil source rock correlation and oil reservoir filling direction.All the Silurian oils and oil sands are characterized by low Pr/Ph and C21/C23 tricyclic terpane（〈1.0） ratios,＂V＂-pattern C27-C29 steranes distribution,low C28-sterane and triaromatic dinosterane abundances and light δ13C values,which can be correlated well with the carbonate source rock of the O3 l Lianglitage Formation.Different oil biodegradation levels have also been confirmed for the different oils/oil sands intervals.With the S1k2 seal,oils and oil sands from the S1k1 interval of the Kelpintag Formation have only suffered light biodegradation as confirmed by the presence of ＂UCM＂ and absence of 25-norhopanes,whereas the S1k3-1 oil sands were heavily biodegraded（proved by the presence of 25-norhopanes） due to the lack of the S1k2 seal,which suggests a significant role of the S1k2 seal in the protection of the Silurian oil reservoir.Based on the Ts/（Ts＋Tm） and 4-/1-MDBT ratios as reservoir filling tracers,a general oil filling direction from NW to SE has been also estimated for the Silurian oil reservoir in the Well Shun-9 prospect area.     

Flow Properties of CO2/Crude Oil in Miscible Phase Flooding

Abstract

The high-temperature and high-pressure three-dimensional (3D) device is used to study miscible flooding of CO₂ and crude oil. The experiment model is a real sand plate. In oil reservoir condition, there is a large difference between production and injection volume. The complex flowing characteristics of CO₂ flooding in pore media are observed in recovery, water cut, and gas–oil ratio curves. By analyzing the water saturation contour plot measured by a saturation probe, CO₂ and oil can be miscible. The viscosity of miscible liquid and flowing pressure decreases. This is the important mechanism of enhanced oil recovery. When the viscosity of miscible liquid and flowing pressure decreases, miscible CO₂ and oil contacted with water can make a similar three phase. This is the important mechanism of enhanced oil recovery. Based on the conclusion, the main reason for the production and injection difference is that high-density CO₂ would flow into pore media in which water and oil cannot flow.     

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.     

Effects of low-salinity water coupled with silica nanoparticles on wettability alteration of dolomite at reservoir temperature

Wettability alteration in porous media is one of the mechanisms for enhancing oil recovery through injecting low-salinity water into carbonate reservoirs, in which active ions can remove the carboxylic oil component from the rock surface, altering the rock's wettability toward a water-wet condition. This study investigated the concomitant effects of low-salinity water and hydrophilic SiO₂ nanoparticles on oil-wet dolomite rock. Results revealed that low-salinity water coupled with hydrophilic nano-SiO₂ in oil-wet dolomite rock remarkably affected the wettability alteration of the rock, showing that the simultaneous presence of ions in water and hydrophilic nano-SiO₂ led to considerable wettability alteration compared with using just low-salinity water.     

Asphaltene Deposition under CO2 Injection: An Experimental Study of the Bangestan Reservoir of Ahwaz Oilfield,SW Iran

Abstract

It is essential that precipitation of asphaltenes is recognized early in the planning stage of any CO₂ enhanced oil recovery (EOR) project so that appropriate testing can be performed to evaluate whether there will be a negative impact on reservoir performance. This article presents detailed evaluations of slim tube data that were obtained during CO₂ injection using a medium-gravity Iranian crude oil.

A crude oil from Bangestan reservoir of Ahwaz oilfield containing 18.2% asphaltenes with ~31.5 °API gravity was flooded by purified CO₂ (>96% CO₂) in a slim tube apparatus under 2,700 psi at 110°C. We were going to determine the minimum miscibility pressure (MMP) of the sample oil under injection of CO₂ flood, but when a CO₂ slim tube test was performed for this oil at 2,700 psi, less than half of the saturated oil in the tube was recovered, which implied that the displacement process was immiscible. At this pressure, the asphaltene deposition in the slim tube apparatus was so severe that even a pressure gradient of 6,200 lb/in² was not able to displace any fluid through the capillary tube. Therefore, we abandoned MMP determination with this sample and investigated the problem.

Due to the high percentage of asphaltenes in the sample, using the slim tube MMP as an apparatus for determining minimum miscibility pressure of CO₂ and sample oil can be misleading.     

驱油用超高分子量聚丙烯酰胺拉伸流变性能研究

聚合物溶液的流变行为对其在油藏多孔介质中的驱油效果影响较大。系统分析了聚合物含量、温度、多种金属离子及机械剪切作用对驱油用超高分子量部分水解聚丙烯酰胺(U-HPAM)及常规中等分子量部分水解聚丙烯酰胺(M-HPAM)溶液拉伸流变性能的影响。实验结果表明:提高聚合物含量能够促进HPAM分子链间纠缠,聚合物的拉伸黏度增加,同时U-HPAM对拉伸黏度的增强幅度远大于M-HPAM;温度升高、外加金属离子(Na⁺、Ca²⁺、Mg²⁺、Fe³⁺和Fe²⁺)含量增大及机械剪切作用增强都会削弱聚合物分子链间纠缠,导致拉伸黏度降低;U-HPAM受温度及Na⁺、Ca²⁺、Mg²⁺、Fe³⁺等的影响明显小于M-HPAM,而Fe²⁺及机械剪切对两类HPAM影响程度相似。渗流及岩心驱替实验表明,U-HPAM比M-HPAM具有更强的调剖能力,在强非均质油藏中更能发挥其高效驱油能力。 