提高采收率技术矿场应用进展与发展方向

通过对不同国家提高采收率技术(EOR)应用情况进行分析、统计,了解提高采收率技术的应用状况和发展趋势。2014年,世界EOR产量约为46.1×104m3/d,约占世界产油量的3.3%。稠油热采、气驱和化学驱技术是世界工业化应用的三大提高采收率技术。其中,稠油热采技术相对成熟,应用规模最大,其产量接近世界EOR产量的一半;气驱和化学驱技术发展较快,应用规模不断扩大,其产量约占世界EOR产量的四分之一。在高油价下,提高采收率技术得到更为广泛的关注,多个国家都重视新技术、新方法的研究与试验。美国、中国、加拿大、委内瑞拉和俄罗斯是提高采收率技术应用规模较大的5个国家,中国的化学驱和稠油热采技术及应用规模居世界前列,已成为提高采收率技术应用大国。适应苛刻油藏条件的驱油剂、驱油体系和流度控制技术,是制约提高采收率技术工业化应用的瓶颈;不同成熟技术的组合应用将是提高采收率技术的发展方向。     

Evaluation of CO2 enhanced oil recovery and sequestration potential in low permeability reservoirs,Yanchang Oilfield,China

Sequestrating CO₂ in reservoirs can substantially enhance oil recovery and effectively reduce greenhouse gas emission. To evaluate the potential of CO₂ enhanced oil recovery (EOR) and sequestration for Yanchang Oilfield in China, a screening standard which was suitable for CO₂-EOR and sequestration in Yanchang Oilfield was proposed based on its characteristics of strong heterogeneity, high water content and severe fluid channeling after water flooding. In addition, an efficient calculation method – stream tube simulation method was presented to figure out CO₂ sequestration coefficient and oil recovery factor. After screening and evaluating, it turned out that 148 out of 176 blocks in 22 oilfields were suitable for CO₂-EOR and sequestration. CO₂ flooding after water flooding can produce 180.21 × 10⁶ t more crude oil and sequestrate 223.38 × 10⁶ t CO₂. The average incremental oil recovery rate of miscible reservoirs was 12.49% and the average CO₂ sequestration coefficient was 0.27 t/t while the two values were 6.83% and 0.18 t/t for immiscible reservoirs. There are comparatively more reservoirs that are suitable for CO₂-EOR and sequestration in Yanchang Oilfield than normal, which can obviously enhance oil recovery and means a great potential for CO₂ sequestration. CO₂-EOR and sequestration in Yanchang Oilfield has a bright application prospect.     

Application of different EOR techniques for the energy and recovery of Ashal’cha oil field

In this research, utilizing the reservoir and produced oil data, different enhanced oil recovery (EOR) techniques known as in-situ combustion, CO₂ flooding, and steam flooding were applied for Ashal’cha oil field in Republic of Tatarstan, Russia. For this purpose, In-Situ Combustion Predictive Model (ICPM), CO₂ Miscible Flood Predictive Model (CO₂PM) and Steam-flood Predictive Model (SFPM) are used. In addition to oil recovery, economic analysis of the discussed EOR applications was also conducted. By using the oil price forecast for 10 years, each EOR method is analyzed using their expenses and outcomes separately. Comparison among the EOR applications regarding the oil production, and economic feasibility was also given. Taking the reservoir and produced oil characteristics, oil production rate and economical payout time into account, it was observed that in-situ combustion is the most feasible and practical EOR method for Ashal’cha oil field.     

Sensitivity analysis and optimization on effective parameters during chemical enhanced oil recovery (CEOR) using experimental design and numerical simulation

Several factors effect on choosing the best enhanced oil recovery process in a hydrocarbon reservoir. In the present study, effective factors on chemical enhanced oil recovery involved in polymer flooding, surfactant flooding, surfactant–polymer flooding, and alkaline–surfactant–polymer flooding are discussed in numerical simulation. The numbers of the simulation runs are estimated based on the number of factors and their maximum and minimum values using experimental design software. Oil recovery factor from reservoir simulation is considered as comparison factor in all of the run cases. The results from one parameter and two interaction factors during each flooding case were analyzed by Tornado and Parto plot. The oil recovery factor also was estimated using statistical analysis using Minitab. The results show that there is a strong correlation between simulation and statistical analysis. Furthermore, the results show that each selected factor has a different effect on oil recovery in each case of chemical flooding. The case study results on two Iranian oil fields at the end of the present study clarified that results of this study can be useful for selecting the best chemical process for oil reservoir based on reservoir properties.     

Investigation of the effects of low-salinity waterflooding for improved oil recovery in carbonate reservoir cores

Water injection for both pressure maintenance and oil displacement is the most important secondary recovery method in sandstones. It has also been implemented with success in a few carbonate reservoirs, but because the most carbonate reservoirs worldwide are characterized as neutral to preferential oil-wet, normal waterflooding is usually not successful as an enhanced oil recovery (EOR) technique. It has been proved that seawater can be used as an EOR fluid for hot, fractured carbonate oil reservoirs since it is able to modify the wetting conditions and to enhance the oil recovery. The potential determining ions in seawater such as Ca²⁺, Mg²⁺, and SO₄^2- played a crucial role in altering the wettability from oil-wet to more water-wet condition because of their reactivity towards the carbonate surface. In this paper, the potential of low-salinity brine to enhance the oil recovery has been studied. Four flooding tests were conducted on both limestone cores containing anhydrite and chalk core containing no sulfate. It is observed that low-salinity brine had only effect on rocks containing anhydrite. The dissolution of anhydrite, CaSO₄, which is the source for SO₄^2-, is depending on salinity/composition of brine and the temperature. The dissolution of anhydrite normally increases as the temperature decreases. Lowering the salinity of injection brine increases the reactivity of the surface-active ions SO₄^2- and Ca²⁺.     

An evaluation of enhanced oil recovery strategies for a heavy oil reservoir after cold production with sand

Cold heavy oil production with sand (CHOPS) is the process of choice for unconsolidated heavy oil reservoirs with relatively high gas content. The key challenge of CHOPS is that the recovery factor tends to be between 5% and 15%, implying that the majority of the oil remains in the ground after the process is rendered uneconomic. Continued cold production (without sands) is not productive for a post‐CHOPS reservoir because of the low oil saturation and depleted reservoir pressure in the wormhole regions. There is a need to develop viable recovery processes for post‐CHOPS reservoirs. Here, different follow‐up processes are examined for a post‐CHOPS heavy oil reservoir. In post‐CHOPS cold water flooding, severe water channeling is ineffective at displacing high viscosity heavy oil. Hot water flooding improves the sweep efficiency and produces more oil compared with cold water flooding. However, the swept region is limited to the domain between the neighboring wormhole networks, and the energy efficiency of the process is relatively poor. Compared with the hot water flooding case, steam flooding achieves higher oil production rates and lower water use. A cyclic steam stimulation strategy achieves the best performance regarding oil production rates and water usage. Based on our results, it is observed that thermally based techniques alone are not capable to recover the oil economically for post‐CHOPS reservoirs. However, it is suggested that techniques with combined use of thermal energy and solvent could potentially yield efficient oil recovery methods for these reservoirs. Copyright © 2015 John Wiley & Sons, Ltd.     

Experimental studies of ionic surfactant adsorption onto carbonate rocks

One of the main factors in chemical-based enhanced oil recovery, especially surfactant flooding, is a surfactant adsorption loss onto the reservoir rock. The main aim of this article is performing systematically a study on the adsorption behavior of an industrial ionic surfactant, which is currently employed in petroleum upstream. It is worth mentioning that sodium dodecyle sulphate was employed as an ionic surfactant in this study. Moreover, adsorption density at equilibrium condition was determined. Crushed carbonate rocks were used as rock samples. To determine adsorption behavior of the aforementioned surfactant onto carbonate surface, various surfactant concentrations were created in the range of 500 to 5,000 ppm. Furthermore, via using an electrical conductivity measurement, the surfactant concentration in each solution before and after contacting with carbonate rocks was determined. Two well-known adsorption isotherms, including Freundlich and Langmuir, were employed to specify the adsorption mechanism. Based on the experimental results the Freundlich adsorption isotherm can predict the adsorption behavior of SDS onto carbonate rock surface.     

Efficacy of Bacillus subtilis for the biodegradation and viscosity reduction of waxy crude oil for enhanced oil recovery from mature reservoirs

Increasing maturity of the crude oil reservoirs across the world have led to the production of waxy crude oil which need economical and efficient methods for enhanced oil recovery (EOR). The studies on the performance of bacteria in the presence of waxy crude oil is rare. In this study, experiments were performed to understand the efficacy of thermophillic microorganism Bacillus subtilis on the biodegradation of waxy crude oil for EOR applications. Bacterial growth, changes in crude oil composition, viscosity reduction, and surface and emulsification activity have been monitored to evaluate the oil degradation capabilities of the bacteria. This study also presents the effect of temperature, salinity, pH, and pressure on the stability of the produced biosurfactant for EOR applications. The biosurfactant produced by bacteria in the presence of crude oil was found to be stable up to 120°C, 10 MPa, 15% salinity, and wide range of pH, and thus favorable for reservoir environment. The crude oil composition before and after degradation at 75°C was determined using gas chromatography-mass spectroscopy and observed to be 60% in one day, while the maximum viscosity reduction was found to be 60% from initial values. Experimental results showed that the bacteria used in this work are capable of surviving at reservoir conditions, and are easy to grow on the waxy crude oil for enhanced oil recovery operations.     

Experimental studies of surfactant-polymer flooding: An application case investigation

A great deal of oil field is currently produced using water flooding and the water cut has reached a high level, which requires enhanced oil recovery (EOR) techniques to improve the recovery. Surfactant-polymer (SP) flooding is the combination of surfactant flooding and polymer flooding. The polymer is added to increase the viscosity and viscoelasticity of the fluid while the surfactant is included to decrease the oil–water interfacial tension and change the wettability. Although the mechanism of SP flooding has been deeply investigated, the application of SP flooding on a specific oil field requires the selection of optimal SP system. Therefore, for the first time, we performed a series of experiments to determine the optimal SP system for high water-cut oil field. In the injection capability experiment, we observe that the SP system is injected into the core with less resistance compared with single polymer solution. In the flooding experiment, regardless of the polymer types, the improvement of recovery becomes significant when the injected PVs increases. SP flooding shows the higher improvement of recovery compared with single polymer flooding or surfactant flooding. Based on the performance of recovery improvement, we recommend the optimal SP system for the studied case is the combination of DQ-TSRP01 polymer and surfactant. The optimal injection parameters of this SP system are 1500 mg/L polymer concentration, 0.3 injection PV and the injection timing of 96% water cut. The finding of this study can help for better understanding of the application of SP flooding in high water-cut oil field production.     

Wettability alteration of carbonate reservoir rock using amphoteric and cationic surfactants: Experimental investigation

The objective of this study is to prove that altering the wettability of reservoir rocks by two surfactants (hexadecyl amino benzene sulfonic acid [HABSA] and cationic hexa decyl trimethyl ammonum bromide [CTAB]). Changing the wettability to preferentially water-wet condition will reduce the residual oil saturation (S_or). Because of reducing S_or, the percentage of recovered oil is increased. All surfactants were tested for their ability to alter the wettability of reservoir rocks. This alteration was measured based on the contact angle methods. Results of this study show that both amphoteric HABSA and CTAB surfactants alter the wettability of carbonate rocks from oil-wet to water-wet, while CTAB alters the wettability from oil-wet to water-wet more than HABSA. Also, recovery factor in CTAB injection was more than HABSA injection. Ultimately, the results show that the CTAB surfactant is more effective than HABSA surfactant to alter the wettability and improve oil recovery from carbonate reservoirs.     

Dynamic Interfacial Tension between Crude Oil and Dodecylmethylnaphthalene Sulfonate Surfactant Flooding Systems

Abstract

The surface tension of surfactant aqueous solutions and dynamic interfacial tensions (DIT) between crude oil, offered from Shengli Oil Field in China, and surfactant flooding systems, and the single-component dodecylmethylnaphthalene sulfonate (DMNS) surfactant, developed in our laboratory, were measured. In the present report, both buffered alkali and no alkali flooding systems were investigated. It was found that DMNS surfactant possessed great capability and efficiency of lowering the solution surface tension and the critical micelle concentration (cmc) is 0.002 mass% and the surface tension at this concentration is 29.39 mN.m^?1. It was also found that the DMNS surfactant is also greatly effective in reducing the interfacial tensions and can lower the tension of crude oil-water interface to ultra-low at very low surfactant concentration and an optimum range of sodium chloride. The lower alkali concentration is favorable for lowering DIT. The higher alkali concentration needs a higher surfactant concentration for oil flooding systems lowering DIT. Moreover, the results indicate that there obviously exists both synergism and antagonism among the surfactant, alkali and inorganic salt. The added surfactant play an important role in reducing DIT, and the prepared DMNS surfactant possesses great capability and efficiency in lowering the interfacial tension between oil and water. The salt-modified surfactant flooding systems without alkali, decreasing the cost of oil recovery and avoiding the stratum being destroyed would have a great prospect for enhanced oil recovery.     

中原油田提高采收率优化技术

中原油田相继开展了CO2吞吐、N2驱、空气驱、合成聚合物驱、交联聚合物驱、微生物采油等项现场试验。鉴于中原油田地层温度高、地层水矿化度高,常规三次采油技术难以适应。对中原油田提高采收率的技术进行优化分析,对油田地质特点、开采特点和不同类型油藏采收率现状进行归纳,并对各技术潜力进行分析,得出结论:从储层条件和原油性质来看,适用中原油田的三次采油方法是CO2混相驱、天然气非混相驱,其次是化学驱。研究预测显示,通过水驱综合调整和气驱,可提高采收率11.1个百分点,达到40.5%,其中水驱综合调整增加可采储量3841×104t,提高采收率7.4个百分点,三次采油提高采收率3.7个百分点。总结出中原油田提高采收率的方向和思路:水驱提高采收率仍是油田当前开发的重点,重组开发层系、强化差层开采、提高油藏水驱采收率,大力发展堵水调剖等配套工艺技术、提高水驱控制程度,气驱仍是今后的主要发展方向。     

Effects of relative permeability change resulting from interfacial tension reduction on vertical sweep efficiency during the CO2-LPG hybrid EOR process

The addition of liquefied petroleum gas (LPG) to the CO₂ stream reduces interfacial tension (IFT) between the injected gas and the reservoir oil, and it changes the gas-liquid relative permeability by making it more water-wet, which affects not only the oil mobility, but also the vertical sweep efficiency. The reduction of the IFT decreases vertical sweep efficiency because it enhances the relative permeability of the solvent, resulting in an increase in the viscous gravity number. For CO₂-LPG enhanced oil recovery (EOR), oil recovery is enhanced by up to 47%, as compared to CO₂ flooding, when the relative permeability change caused by the IFT is not considered. By taking the vertical sweep-out caused by IFT and relative permeability change into consideration, this increase is reduced to 40%. These results indicate the importance of considering the relative permeability and IFT change when predicting the performance of the CO₂-LPG EOR process.     

Dynamic Interfacial Tension Between Crude Oil and Octylmethylnaphthalene Sulfonate Solution

The surface tension of surfactant aqueous solutions and dynamic interfacial tensions (DIT) between Shengli Oilfield crude oil and solution of octyl methylnaphthalene sulfonate surfactants (OMNS) have been measured. The effects of various parameters such as surfactant concentration, salinity and sodium carbonate concentration on the interfacial behavior of crude oil-water were investigated. It was found that the prepared surfactants can reduce the interfacial tension to ultra-low only at certain surfactant concentration, salinity and alkaline concentration ranges. It was also found that there exist optimum values with respect to all of surfactant concentration, salinity and alkaline concentration. The DIT can low to 10^?6 mN.m^?1 under the optimum conditions. Moreover, the DIT behavior of OMNS flooding without alkaline has also been investigated. It was found that the DIT also reaches ultra-low value under the optimum sodium chloride concentration without alkaline. The results show that the OMNS is more effective on lowering surface tension of aqueous solutions and dynamic interfacial tensions (DIT) between crude oil and water. OMNS possesses a great potential to be used in EOR with low costs and high efficiency.     

中深层稠油蒸汽驱注采剖面调整工艺技术研究

从1997年开始,辽河油田进行了中深层稠油蒸汽驱先导试验,目前已进入蒸汽驱先导试验的后期调整阶段,先导试验区的稠油采出程度由试验前的24%提高到57%,基本达到方案设计指标,先导试验获得成功。然而,在蒸汽驱先导试验及随后的扩大试验中,存在着纵向动用程度不均、平面动用程度差等问题,影响蒸汽驱先导试验效果。为此,从2004年开始,辽河油田钻采工艺研究院开展了中深层稠油蒸汽驱注采剖面调整工艺技术研究工作,形成了中深层稠油蒸汽驱注采剖面调整系列技术,主要包括耐高温化学调堵技术与机械封堵技术,并应用于现场,有效解决了蒸汽驱层间、层内动用不均的问题,提高了中深层稠油的采收率。下一步仍需加大高温调剖剂的深入研究,研制高效、经济的高温调剖剂;对生产井机械封堵工艺技术的研究重点,是加快对耐高温胶筒的选优,满足现场生产需求。     

高压注空气提高采收率的影响因素研究

近年来,高压注空气法在轻质油油藏中的应用取得了显著效果,并受到广泛关注。本文回顾高压注空气技术的发展过程及其最新进展,列举了几个典型的注空气项目及其主要参数。分析高压注空气技术的驱油机理认为,轻质原油注空气是一种以烟道气驱与热效应作用为主的驱油方式。基于对美国大量注空气项目的地质特征分析,总结了注空气项目的地质影响因素及油藏筛选标准,包括室内筛选标准和矿场筛选标准。从生产井、注入井及其他生产设施等方面,分析注空气安全方面存在的主要问题和解决措施。室内实验和矿场应用结果表明:高压注空气驱油技术是一项经济有效的提高采收率方法,特别适用于低渗透、高压、深层、轻质油油藏,既可用于注水后油田的三次采油,也适用于注水困难的低渗油田的二次采油,还可以与注水技术并用,保持地层压力及重力稳定驱油。备受关注的注空气安全问题也逐渐得到缓解,高压注空气技术前景广阔。     

A dual-porosity dual-permeability model for acid gas injection process evaluation in hydrogen-carbonate reservoirs

The Pre-Caspian basin is one of the most prolific in terms of oil and gas exploration and hydrogen and carbon compounds energy production around the world. The major hydrogen and carbon compounds reservoirs are Carboniferous reef and platform hydrogen-carbonate rocks. The original fluids under subsurface conditions contain 15% hydrogen sulfide and 4% carbon dioxide. Acid hydrogen and carbon compounds reinjection is not only an environmentally friendly solution for disposal of produced greenhouse gases but also enhances oil recovery and supplies more fuel energy. On the other hand, the presence of fractures makes hydrogen-carbonate reservoir characteristics nature more complicated than conventional sandstone reservoirs, which leads to a tremendous challenge to evaluate the gas injection process. In this work, a dual-porosity dual-permeability formulation was used to model the dual-medium nature incorporating matrix system with high porosity and low permeability and fracture network with low porosity and high permeability. After matching PVT experiments, a ten pseudo-components fluid model was generated for running compositional simulation. The miscible hydrogen and carbon compounds injection was simulated as an effective enhanced oil recovery approach. Sensitivity analysis such as timing of injection gas, injection rate, well spacing and completion interval have proposed the optimal condition for the miscible hydrogen and carbon compounds flooding. The recommended optimum hydrogen and carbon compounds injection scenario is twice higher oil recovery compared with natural depletion. The results of this study illustrate further the practicability of pseudo-components splitting and lumping for compositional simulation to evaluate the performance of hydrogen and carbon compounds injection processes, and are of great importance using the dual-porosity dual-permeability method performing numerical simulation of naturally fractured hydrogen-carbonate reservoirs.     

不同二类油层水驱及聚驱驱替规律研究

总结萨北开发区二类油层水驱与聚驱规律,为编制开发方案提供依据,进行了室内水驱、聚驱实验。实验按常规驱油实验步骤进行,首先水驱至含水率98%,然后开始转注聚至不出油。实验结果表明,在水驱段,萨尔图组和高台子组二类油层的水驱采收率均与有效渗透率呈正相关关系,其水驱开发指标预测也皆可沿用一类油层的水驱驱替特征曲线方法;相同渗透率下,萨尔图层的水驱采收率要高于高台子层,说明其油层物性更好。在聚驱段,在相同渗透率,以及水驱后注入相同相对分子质量、相同浓度的聚合物溶液的条件下,高台子组的二类油层岩心两端压差变化更加明显,而萨尔图油层注聚量小于高台子层。萨尔图组和高台子组二类油层的采收率在半对数坐标系下均与水油比呈二次函数关系,可以用此关系预测萨尔图组和高台子组二类油层的聚驱开发指标。     

Optimizing a CO2 value chain for the Norwegian Continental Shelf

This paper presents a mathematical model for designing a carbon dioxide (CO₂) value chain. Storage of CO₂ in geological formations is recognized as an important alternative for carbon abatement. When CO₂ is deposited in oil reservoirs it can sometimes be used to achieve additional oil production, enhanced oil recovery (EOR). The model determines an optimal CO₂ value chain from a fixed set of CO₂ emission points and a set of potential injection sites. It designs a transport network and chooses the best suited oil fields with EOR potential or other geological formations for storage. A net present value criterion is used. The model is illustrated by an example of a Norwegian case with 14 oil fields, two aquifers and five CO₂ sources. A sensitivity analysis is performed on the most important parameters.