Maximizing the Oil Recovery Through Miscible Water Alternating Gas (WAG) Injection in an Iranian Oil Reservoir

In recent years there has been an increasing interest in water alternating gas (WAG) processes, both miscible and immiscible. Microscopic oil displacement and sweep efficiency of waterflooding and continuous gas injection can be improved by WAG injection. In this work, by designing various scenarios of water and gas injection, WAG injection and simultaneously water and gas injection, the recovery and residual oil saturation obtained by implementing these methods are compared to choose the appropriate method of injection. The results showed that simultaneously the water and gas injection method has the highest recovery but from economic view, WAG process is the best enhanced oil recovery method to increase the recovery. In WAG method, the values of gas oil ratio and water cut are the smallest, so in this case, operational and process facilities problems and their costs are the minimum.     

Integrated Investigation of Enhanced Oil Recovery in South Slattery Minnelusa Reservoir,Part 2: CO2 Miscible Injection

Abstract

The authors used experiment and full-field reservoir modeling to investigate and optimize the design of a CO₂ miscible flooding project for the Minnelusa reservoir of the South Slattery field. Minimum miscibility pressure and core flooding tests were conducted to estimate the CO₂ injection feasibility at Slattery conditions. A full-field CO₂ model with finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO₂ model identified the best patterns for CO₂ flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO₂ flood. Continuous CO₂ miscible injection (CMI) and alternating (WAG) were simulated. WAG injections were simulated mainly to observe the improvement of low sweep efficiency caused by override and unfavorable mobility ratio. The integrated recovery efficiency comparison of CMI and WAG was used to demonstrate the mobility control of the WAG process.     

An Experimental Investigation of Foam for Gas Mobility Control in a Low-Temperature Fractured Carbonate Reservoir

Abstract

This work concerns the experimental investigation of surfactant alternating CO₂ injection in carbonate rocks. The core samples provided from a low-temperature fractured light oil reservoir, located in southwest Iran. The experiments were designed to observe the effect of CO₂–foam injection on gas mobility and oil recovery at different surfactant concentrations. The core samples were initially saturated with synthetic/field brine, 5,000 ppm, and then flooded with live oil to reach connate water saturation at reservoir condition, 115°F and 1,700 psia. The commercial surfactant used was sodium lauryl sulfate as an anionic surfactant. The results of this work, along with field-scale simulation and/or economic considerations, could be helpful in making reliable decisions about optimum condition of foam-assisted water-alternating-gas (FAWAG) processes.

Core flooding results demonstrated that macroscopic sweep efficiency increased due to foam generation inside the core. In addition, it led to an increase of between 5 and 12% in the recovery factor in comparison to a water-alternating-gas (WAG) process. Furthermore, the value of the critical micellar concentration for the surfactant–oil system was about 2,000 ppm.

After primary and secondary recovery processes, there is a large amount of trapped oil in the reservoir. Extensive research has been directed toward enhancing the recovery of this oil, but limited success has been achieved. FAWAG injection appears to have more applicability to recover the trapped resources. However, little attention has been paid to experimental investigation of FAWAG processes in low-temperature oil reservoirs.     

An Investigation of the Effect of Using Foam in WAG Injection in an Iranian Oil Reservoir

The effect of using foam in water alternating gas injection method as an enhanced oil recovery method in one of Iranian oil reservoirs was investigated. The model of under investigation has high vertical permeability in vertical direction, so injected gas front would be breakthrough early times of injection periods. Foam implemented in injected gas phase of water alternating gas injection by decreasing the mobility of the gas phase and improving sweep efficiency of gas phase dominates this problem. In this work foam agent was added in water alternating gas injection method in two manners, with water phase and with gas phase. It was seen higher recovery for adding foam to gas phase in water alternating gas injection method. The results showed that foam increases the resistance of gas phase to flow through high permeable zone. By increasing the concentration of foam agent, total recovery would be increased but the rate of recovery incremental would be reduced after critical foam concentration. To reduce the costs, critical foam concentration must be found.     

The Effect of the Salinity of Injected Water and Reservoir Water on WAG Injection: A Study in an Iranian Reservoir

The effect of salinity of injected water and reservoir water in water alternating gas injection in one of an Iranian reservoir was investigated. Usually in simulation works water salinity of reservoir or salinity of injected water may be ignored. Without applying salinity effect, it would cause estimated overall oil recovery to be different with real. Salinity of water phase would increase the viscosity of injected water also obviously the mobility ratio of oil. Because of this improvement in water mobility, more oil would be displaced toward production wells. The problem of increasing salinity of injected water is that too much salt may harm pump equipments. Over time, salt deposits in pumping devices may cause reduction in pumps efficiency and corrosion of pipes, thus injecting salty water would cause corrosion problems and pump failures. Since the salinity of the reservoir water in the study was not available so it was chosen in two modes: reservoir water without salt (Cs = 0) and with concentration of 140 kg/m³ (Cs = 140). In this work 0.8 reservoir pore volume WAG was injected. Salinity of injected water was varied from zero to 4,800 kg/m³; by increasing salinity of injected water, because of mobility ratio increment between water and oil, production efficiency would be increased. The economic dimension of this view must be examined. By considering reservoir water salinity, recovery would be increased in WAG injection.     

An Experimental Study on the Applicability of Water-alternating-CO2 Injection in the Secondary and Tertiary Recovery in One Iranian Reservoir

Abstract

The objective of this study was to experimentally investigate the performance of water-alternating gas (WAG) injection in one of Iran's oil reservoirs that encountered a severe pressure drop in recent years. Because one of the most appropriate studies to evaluate the reservoir occurs generally on rock cores taken from the reservoir, core samples drilled out of the reservoir's rock matrix were used for alternating injection of water and gas. In the experiments, the fluid system consisted of reservoir dead oil, live oil, CO₂, and synthetic brine; the porous media were a number of carbonate cores chosen from the oilfield from which the oil samples had been taken. All coreflood experiments were conducted using live (recombined) oil at 1,700 psi and reservoir temperature of 115°F. A total of four displacement experiments were performed in the core, including two experiments on secondary WAG injection and others on the tertiary water and gas invaded zones WAG injections. Prior to each test porosity and permeability of dried cores were calculated then 100% water-saturated cores were oil-flooded to obtain connate water saturation. Therefore, all coreflooding tests started with the samples at irreducible water saturation. Parameters such as oil recovery factor, water cut, and gas-oil ratio and production pressure of the core were recorded for each test. The most similar experimental work with the main reservoir condition, indicated that approximately 64% oil were recovered after 1 pore volume of WAG process at 136,000 ppm brine salinity. Although tests show ultimate recovery of 79% and 55% for secondary and tertiary injection in gas and water invaded zones, respectively, immiscible WAG injection efficiency in the gas and water invaded zones will not be proper. In the similar test to field properties, the average pressure difference about 70 Psig was observed, which shows stable front displacement. These experiments showed that there was significant improvement in the oil recovery for alternating injection of water and CO₂, especially in the secondary recovery process. Water breakthrough time in almost all of the tests shows frontal displacement of injected fluid in cores and produced gas-oil ratio changes a little whenever the injection is miscible and increases rapidly in immiscible processes.     

Experimental investigation of effect of asphaltene deposition on oil relative permeability,rock wettability alteration,and recovery in WAG process

Asphaltene deposition is considered to be one of the most problems during oil productions. This work describes the effect of asphaltene precipitation and deposition on relative permeability of reservoir rock during water alternating gas (WAG) injection process. The main objective of this work is experimental investigating of relative permeability change of reservoir fluid due to asphaltene deposition on application of WAG process by use of core flood setup. Result of this paper investigate the relative permeability change during WAG process with different asphaltene content that help to make better development decisions for a reservoir with fluid with specific asphaltene content.     

A Rheological Study of Polymer Using Precipitation Inhibitor,Alkali, and Surfactant for High Salinity in Carbonate Reservoirs

In the present study, a new chemical formulation is designed by combining acrylic acid with the conventional alkali-surfactant-polymer (ASP) components. Acrylic acid generates precipitation inhibitor that dissolves insoluble salts. The salts known as precipitations are formed by the reaction of added chemicals with carbonate reservoir minerals or brine compositions. Various fluid-fluid compatibility tests were first performed to find an optimum acid-alkali ratio to keep ASP solutions without any precipitations for 30 days at 80°C. Using the optimum ratio, a comprehensive study was conducted to investigate the impact of acid, acid-alkali, and acid-alkali-surfactant on the viscosity of copolymer. The optimum acid-alkali ratio was found 0.6:1.0. It was observed that blend of acid with ASP solutions did not cause significant impact on the polymer viscosity. This new chemical combination provided sufficient viscosity for mobility control in the hard brine environment. Hence, the main feature of this work is the development of acid-ASP formulation, which can be more feasible for enhanced oil recovery in carbonate reservoirs as compared to conventional ASP.     

水驱废弃油藏注二氧化碳驱室内试验研究

为探讨进一步提高高温、高盐水驱废弃油藏采收率潜力,以河南濮城沙一下亚段油藏为目标,开展了注入CO2流体性质变化、细管驱替、长岩心驱替室内试验。试验验证了注入CO2可改善原油流动性、有效增加地层能量和可动油等驱油机理;油藏原油性质好,混相压力低,目前油藏条件可达到混相;优选CO2/水交替驱为最佳注入方式;优化了注入段塞组合;组分检测分析认为CO2/水交替驱波及到了水波及不到的原油。研究结果为濮城沙一下亚段油藏CO2驱矿场试验提供了技术支持,并对其他特高含水期油藏注CO2进一步提高采收率同样具有借鉴意义。     

An Integrated Reservoir Characterization Analysis in a Carbonate Reservoir: A Case Study

Abstract

Reservoir characterization is one of the most challenging subjects in carbonate reservoirs. In this study flow zone index (FZI), Winland, and initial water saturation methods were used to classify rock typing in an Iranian oil field. In addition, stratigraphic modified Lorenz plots were generated for the purpose of identifying the flow zone and barriers in each well. The results were consistent with Winland result and FZI. The scanning electron microscopy photomicrographs, pore throat radius, grain size distribution data, and thin section of the obtained rock type were studied and found to be consistent with the findings of this work.     

The Experimental Investigation of Nitrogen and Carbon Dioxide Water-alternating-gas Injection in a Carbonate Reservoir

Abstract

Floods were conducted using rock–fluid systems consisting of carbonate cores from Binak reservoir, which is located in southwest of Iran, oil and brine. The coreflood protocol consisted of a series of steps including brine saturation, absolute permeability determination, flooding with oil to initial oil saturation, endpoint oil permeability determination, and, finally, nitrogen and carbon dioxide water-alternating-gas (WAG) injections. The effect of slug size on oil recovery was investigated using immiscible nitrogen (N₂) WAG injection and the amount of oil recovered was compared with continuous injection of N₂. Experimental results show that ultimate oil recovery is not very sensitive to changing the slug sizes for N₂ WAG injection, although the slug size of 0.15 pore volume (PV) injection is better than others. As less PV is injected, a higher oil production rate is achieved. Also, N₂ WAG flood appeared to be better in performance than continuous gas injection (CGI) of nitrogen. Carbon dioxide (CO₂) injection was performed in three modes, including CGI, WAG injection, and hybrid WAG. Experimental results show that for optimization of oil recovery in CO₂ floods, a continuous gas slug of 0.4–0.5 PV followed by 1:1 WAG needs to be injected.     

ND油田火山岩油藏开发技术研究与应用

在油藏地质综合研究的基础上,形成了火山岩有效储层识别方法,有效层测井解释符合率由58.3%提高到85.7%;形成了火山岩有效储层预测方法,储层预测符合率从60%提高到76.7%;形成了火山体刻画技术,为优化钻井和措施调控提供了理论基础。在前期注水效果分析的基础上,初步形成了火山岩注水开发技术,ND油田轴部区整体注水后,预计可提高采收率6%~8%。研究结果为STH盆地火山岩有效开发提供了技术保障。     

文72块沙三中油藏天然气驱可行性试验研究

根据文南油田72块沙三中油藏的性质和流体特征，通过室内细管驱替试验和长岩心驱替试验研究，表明注入天然气组成达到一定比例和注入气和温度大于某一临界值，就可以对该油藏进行注烃类气体混相驱，说明注气开发是可行的，并能够提高油藏的采收率。     

碳酸盐岩缝洞型油藏提高采收率关键技术

中国碳酸盐岩缝洞型油资源量丰富,探明石油地质储量达29.3×10⁸ t,已经成为中国油气勘探开发和油气增储上产的重要领域。由于深埋5 500 m碳酸盐岩缝洞体的描述精度低、流动模式多样、模拟预测难度大,注水窜流易造成油井暴性水淹,导致采收率低仅为15.9%,此类油藏开发是世界级难题。经过多年的研究与实践,形成地球物理描述、地质建模、注水注气和酸压改造等提高采收率系列技术,单元应用后储量动用率提高了42%,同时已提高采收率2.3%,对同类深层、超深层强非均质性油藏开发具有借鉴作用。     

塔河油田碳酸盐岩储层用新型长效酸液体系的实验研究

塔河油田碳酸盐岩储层酸压要求酸液具有耐高温、延缓反应速率和降低滤失速率的性能,为此需要研发一种新型长效酸液体系。通过优选聚合物、破胶剂和助排剂,筛选出一种新型长效酸液体系配方：20%HCl＋0.9%聚合物A＋2.5%缓蚀剂H＋1.0%助排剂C＋1.0%破乳剂Q。评价结果表明,该长效酸液体系耐温耐剪切性能好,腐蚀速度低,缓速性能及助排性能好。     

泡沫驱注入量对不同非均质储层驱油效果的影响

为揭示空气泡沫驱对储层的适应性,研究了不同非均质变异系~条件下,泡沫注入量对驱油效果及含水率的影响。结果表明:当注入量为0~0.3 PV时,对于任何非均质性的储层,随着注入量的增加,采收率增幅及含水率降幅均增大,且非均质性中等和非均质性强的储层的变化较大;当注入量为0.35~0.5 PV时,注入量的增加对于非均质性弱和非均质性强的储层的采收率增幅和含水率降幅基本无影响,而对于非均质性中等的储层影响较大;当注入量为0.5~0.6 PV时,注入量增加对于任何非均质性储层的采收率增幅和含水率降幅均无影响。非均质性弱、中等和强的储层的最优注入量分别为0.3、0.4和0.35 PV;泡沫驱采收率增幅最大值分别为13%OOIP、23%OOIP和25%OOIP,含水率最大降幅分别为16.7%、29.7%和33.1%。泡沫驱适用于非均质性中等和非均质性强的储层。     

An Experimental Investigation of Parameters Affecting Oil Recovery Efficiency Alteration during a Microbially Aided Water Flooding Process

Abstract

In order to evaluate the potential of microbial recovery in the Iranian Maroon oilfield, laboratory core flood tests were designed and conducted. The effect of biosurfactant production on the recovery of crude oil during waterflooding and the effect of bioproducts on wettability alteration of the cores was investigated. Three different kinds of microbes in two different kinds of growth media as nutrient media were studied. The results showed that the oil recovery was affected by adjustment time, source of carbon, type of microorganism, phosphorus and nitrogen quantity, and salt concentration. In addition, it was found that there are optimum values of adjustment time, phosphorus and nitrogen quantity, and salt concentration that maximize the oil recovery factor. The results of this work can be helpful for designing and developing successful microbial-enhanced oil recovery (MEOR) operations.     

低渗透油藏天然气驱提高采收率数值模拟研究

针对低渗透油藏的地质及开发特点,在PVT实验和相态拟合的基础上,应用数值模拟技术研究了天然气驱开发方式对开发效果的影响。研究结果表明,注天然气可以较大幅度的提高低渗透油藏的采收率;气水交替驱是最佳的开发方式,并且水驱后气水交替驱的效果比投产初期就采用气水交替驱效果更好。     

碳酸盐岩油藏水平井生产段水淹规律研究

采用水平井注水开发碳酸盐岩油藏的过程中,裂缝的存在会导致注入水突进,引起水平生产井暴性水淹。以国外A油田B区块为例,采用数值模拟方法建立了典型模型,分析了水平井注水开发碳酸盐岩油藏时不同水淹模式下的含水变化规律:若为点状见水,当裂缝位于跟部和中部时含水变化率曲线出现三个峰值,当裂缝位于趾部时含水变化率曲线出现两个明显峰值;若为多点见水,含水变化率曲线出现的峰值数和见水点数呈正相关关系,含水变化率曲线出现的峰值数为见水点数加2,但当裂缝位于趾部时,则峰值数为见水点数加1。结合A油田的生产动态资料,将利用小波除噪方法处理生产数据得到的含水变化率曲线与水淹测井解释结果进行了对比,结果表明,数值模拟结果是正确的、可靠的,可为调剖堵水目标井的筛选及水淹段数的判别提供依据。      

超深断控缝洞型碳酸盐岩油藏注水重力驱油理论探索

在超深层断控碳酸盐岩缝洞组合地质特征与储集单元划分分析基础上,制作了2种物理模型,开展了注水驱油物理模拟试验;探索了断控缝洞型碳酸盐岩油藏复杂流动条件下的注水驱油机理,建立了断控碳酸盐岩油藏渗流和自由流共存状态下的数学模型,并据此开展了矿场注水先导试验,评价注水提高采收率实施效果.研究表明:断控缝洞型碳酸盐岩油藏单元可...