低渗透油藏CO2驱油开发方式与应用

CO₂驱是一种能大幅度提高原油采收率的三次采油技术,国内该项技术的研究和应用起步较晚,多以先导试验为主。苏北盆地溱潼凹陷经过10余年的探索,已经在5个低渗油田开展了CO₂驱先导试验和推广应用,针对这5个油藏利用一维细管模拟和油藏数值模拟方法开展了注气时机、段塞尺寸和注气部位的研究,并应用典型实例进行了分析,认为先期注入提高混相压力,可更有效地缩短两相区过渡带,增加油相中溶解的CO₂含量,降低油相粘度和油气界面张力,进而提高混相程度,更有利于驱油;采用大尺寸段塞可加大CO₂波及区域,较好地保持地层能量,从而提高油井见效率,增强驱替效果;高部位注气可有效地抑制重力超覆,减少CO₂气体过早地产出和突破的机会。就苏北盆地低渗油藏而言,采用先期注入、大尺寸段塞和高部位注气不失为一种成熟有效的提高采收率方法。     

低渗透油藏CO2驱过程中含水率变化规律

通过国内外多个油田水驱后实施CO2驱的矿场实例研究,发现注入CO2后很多油井存在含水率下降的现象;这种现象发生在CO2驱的整个开发阶段,包括注气初期阶段CO2未到达生产井、生产井见气阶段以及高气油比阶段。重点讨论了生产井见气前的开发规律,在该阶段油藏内以油水两相渗流为主,不受三相渗流作用的影响。通过现场动态反应并结合室内细管和长岩心实验,揭示了CO2与油、水2种介质的相互作用,得到了两个结论:第一是始于低含水阶段的CO2驱过程中气体穿越地层水驱替地层油到达生产井;第二是始于高含水阶段的CO2驱替规律在不同级别低渗透岩心中的差异非常明显:对于特低渗岩心,CO2突破前的采出程度占CO2驱总采出程度的73.27%,CO2突破后的采出程度占26.73%,对于一般低渗岩心,CO2突破前的采出程度仅占CO2驱总采出程度的16.72%,而CO2突破后的采出程度占到了CO2驱总采出程度的83.28%。     

稠油油藏注超临界二氧化碳驱油影响因素分析

本文以辽河油田某断块油藏为研究对象,基于室内实验,结合正交设计试验,以提高原油采收率程度为评价指标,开展了稠油油藏注超临界CO_2驱影响因素研究,并分析了不同变量对注超临界CO_2驱油效率的影响权重。结果表明:CO_2驱油效率随渗透率、气体注入量、油藏温度的增加而增加,随原油粘度的增加而降低,其中:渗透率对原油采收率的影响程度最大,其次是原油粘度、气体注入量、油藏温度、压力。最后,本文总结并分析了我国注CO_2驱油提高原油采收率技术存在的主要问题,并提出拟解决措施。     

CO_2-原油体系混相状态的渗流特性

为认识混相状态的CO2在油藏中的渗流特征,利用高温高压三维模拟装置对CO2-地层原油体系在油藏环境条件下的混相驱替过程进行研究.实验发现:模型产出液量与注入量存在较大差异;采收率、含水和气油比曲线亦表现出CO2在孔隙介质中渗流的复杂特征.由实时监测的含水饱和度分布场图分析认为:CO2与原油混相后,流体粘度降低、渗流阻力减小,这是提高采收率的重要原因之一;同时,CO2/原油相与部分接触水能形成近似于三相混相的状态.实验研究还表明CO2以高密度气体形式进入饱和水、饱和油无法进入的微孔隙,这是注入量和产出量不一致的主要原因.     

CO2的地质埋存与资源化利用进展

把CO2注入油气藏、煤层提高油气采收率的方法(CO2-EOR、CO2-EGR、CO2-ECBM),因其在提高石油、天然气和煤层气采收率的同时,又能使一部分CO2永久地埋存于地下,实现油气增产和CO2减排的双赢效果,而成为当今CO2减排最具潜力的现实选择.CO2-EOR(Enhanced Oil Recovery)方法适用于油田开发晚期,通过把CO2注入到比较稳定的油藏,一般可提高油藏采收率达10%～15%;另外把CO2注入到气田中,实施CO2-EGR(Enhanced Gas Recovery).一方面,接近枯竭的气田在没有地层水入侵之前具有巨大的埋存能力,为CO2提供巨大的埋存空间;另一方面注入CO2后,使地层重新增压保持储层中原始的压力,可以保持储层的完整性和安全性.同时,原有的油气圈闭可作为良好的埋存箱能有效地阻止CO2泄漏,使部分CO2能永久地埋存于地下.此外,也可以把CO2注入到煤层中,实施CO2-ECBM(Enhanced Coalbed Methane Recovery),利用煤层对CO2和煤层气(主要为甲烷)吸附能力的差异,实现CO2排替CH4,提高CH4的采收率.     

低渗透油藏水平井注CO2井网优化与影响因素

针对低渗透油藏直井井网CO₂驱油的不足,以大庆某低渗区块为例,建立反七点水平井井网CO₂驱油地质模型。在物性参数相态拟合的基础上,对反七点水平井和五点直井两种不同井网模式的开发效果进行了对比,对反七点水平井井网参数进行了优化,同时对储层非均质(渗透率、储层非均质性、裂缝的发育情况等)进行了影响因素分析。研究表明：利用水平井注CO₂可以适当地增大井距、排距,减少井的数量,降低钻井成本;在生产制度相同的情况下水平井井网的开发效果要比直井井网的开发效果好;在水平井井网中,采出程度随着油井到水平井的垂直距离的比值变化而变化,当比值为1.4时采出程度最大;水平井注CO₂更适合低渗透正韵律储层;在储层裂缝发育的情况下,裂缝条数越多,CO₂在储层中的不均匀推进现象越明显,最终采出程度越低。     

华庆油田长8超低渗透砂岩油藏水驱微观机理

为探讨超低渗透砂岩油藏水驱开发中不同级别孔隙的动用及残余油赋存等问题,对鄂尔多斯盆地华庆地区延长组长8段典型岩样开展水驱油核磁共振实验。定义区间驱油效率、驱油效率贡献,根据核磁共振T2谱形态,分弛豫时间＜10ms孔隙区间、弛豫时间＞10ms孔隙区间、总孔隙区间讨论饱和油状态和水驱最终状态各孔隙区间的含油饱和度、动用含油饱和度、残余油饱和度、驱油效率贡献、区间驱油效率及其与渗透率的相关关系。研究表明,渗透率＜0.07×10-3μm2,原油主要赋存在弛豫时间＜10ms孔隙区间;渗透率＞0.07×10-3μm2,原油主要赋存在弛豫时间＞10ms孔隙区间。弛豫时间＞10ms孔隙,油气富集程度对渗透率更敏感。渗透率越低,弛豫时间＞10ms孔隙的区间驱油效率越高,但其总体积偏低,故水驱开发早期产量高,产量递减快（弛豫时间＜10ms孔隙的区间驱油效率增加缓慢）,这与该类油藏水驱开发特征相吻合。无论渗透率如何低,弛豫时间＞10ms孔隙区间的动用含油饱和度、驱油效率贡献始终高于弛豫时间＜10ms孔隙区间。油藏水驱开发阶段,调整挖潜的对象始终在弛豫时间＞10ms孔隙部分。水驱结束后,渗透率大于0.48×10-3μm2的油藏,残余油主要集中在弛豫时间＞10ms孔隙;渗透率＜0.48×10-3μm2的油藏,残余油主要集中在弛豫时间＜10ms孔隙,这为油藏水驱开发后实施提高采收率技术指明方向。     

聚驱后油藏剩余油分布数值模拟

通常聚合物驱的最终采收率在50%左右,聚合物驱后剩余油具有相当的开采潜力。以大庆长垣北部多段多韵律聚驱主力油藏为例,采用化学驱油藏数值模拟技术,系统研究并总结了典型油藏聚驱后平面及纵向剩余油的分布特征。结果表明,聚驱后油藏剩余油的分布系统可划分为2大成因、3大区域和7个部位。其中:存在受地质因素制约的剩余油,如废弃河道中部、砂体尖灭区、相对孤立的薄差砂体;也有开发因素控制的剩余油,如厚油层顶部剩余油、注采不完善部位、注入井间与生产井附近以及聚驱后高渗层内的残余油。聚合物驱后油藏剩余油主要富集于3大区域内,究其原因则主要源于水驱和后续聚驱波及程度的不同。     

塔河油田缝洞型碳酸盐岩油藏注氮气及注泡沫提高采收率研究

塔河油田开中后期,面临储层天然能量不足,注水开发稳产期短、油井含水率高及采收率偏低等问题针对这些问题。本文利用制作的三维立体仿真模型进行了注N_2驱与注N_2泡沫驱提高采收率效果评价实验。结果表明气水交替驱可提高采收率25.93%,高于恒速N_2驱的23.46%,这是由于气水交替注入不仅有注N_2补充能量的作用,还有注水压锥的效果、同时增加抬升油气界面的速度,延缓了气窜。但恒速N_2泡沫驱与泡沫段塞+后续水驱的提高采收率分别为28.59%和26.54%,明显高于N_2驱,这是因为泡沫破裂后N_2可以启动阁楼油,而表面活性剂能够剥离油膜,起到乳化、携带游离油滴的作用,所以N_2泡沫驱是更为有效的提高缝洞型碳酸盐岩油藏采收率的技术手段。     

应用图像分析法确定两类砂岩油藏的水驱最终采收集

本文的目的是研究由图像分析是得来的孔隙结构特征对油藏最终采收率的影响，并将分析结果同广义同模型相结合进行水驱动态预测。     

Interpretation of carbon dioxide diffusion behavior in coals

Storage of carbon dioxide in geological formations is for many countries one of the options to reduce greenhouse gas emissions and thus to satisfy the Kyoto agreements. The CO₂ storage in unminable coal seams has the advantage that it stores CO₂ emissions from industrial processes and can be used to enhance coalbed methane recovery (CO₂-ECBM). For this purpose, the storage capacity of coal is an important reservoir parameter. While the amount of CO₂ sorption data on various natural coals has increased in recent years, only few measurements have been performed to estimate the rate of CO₂ sorption under reservoir conditions. An understanding of gas transport is crucial for processes associated with CO₂ injection, storage and enhanced coalbed methane (ECBM) production.A volumetric experimental set-up has been used to determine the rate of sorption of carbon dioxide in coal particles at various pressures and various grain size fractions. The pressure history during each pressure step was measured. The measurements are interpreted in terms of temperature relaxation and transport/sorption processes within the coal particles. The characteristic times of sorption increase with increasing pressure. No clear dependence of the characteristic time with respect to the particle size was found. At low pressures (below 1 MPa) fast gas diffusion is the prevailing mechanism for sorption, whereas at higher pressures, the slow diffusion process controls the gas uptake by the coal.     

二氧化碳羽流地热系统的碳封存经济分析

【研究目的】 二氧化碳羽流地热系统（CPGS）在取热的同时可实现CO₂地质封存，在碳达峰与碳中和背景下，CPGS碳封存的经济性是众多学者关注的要点。【研究方法】 以松辽盆地泉头组为例，采用数值模拟方法对比分析了注入压力、井间距与回注温度对热提取率的影响，在供暖情景下，计算了CPGS供暖效益与碳封存成本，并与常规水热型地热系统供暖效益进行了对比。【研究结果】 受携热介质转变与热突破影响，CPGS开采井温度呈现“降低-稳定-降低”的趋势，其中井间距对开采井温降影响显著，井间距越小开采井温降越明显；热提取率与回注压力呈现正相关性，与回注温度呈现负相关性，井间距对热提取率影响不显著；CPGS与常规水热型地热系统相比，采热量呈现“高-低-高”三个阶段，其中回注压力越小、回注温度与储层温度越接近，实现CPGS较水介质多采热能所需的时间越短。【结论】 仅考虑CO₂价格与取热效益，供暖收益抵消部分碳封存成本后，井间距对CO₂封存单位成本影响最为显著，井间距越小，CO₂封存单位成本降低越迅速，在注采井间距300 m条件下，持续开采30 a后CO₂封存单位成本可降至160元/t。     

Geologic factors controlling CO2 storage capacity and permanence: case studies based on experience with heterogeneity in oil and gas reservoirs applied to CO2 storage

A variety of structural and stratigraphic factors control geological heterogeneity, inferred to influence both sequestration capacity and effectiveness, as well as seal capacity. Structural heterogeneity factors include faults, folds, and fracture intensity. Stratigraphic heterogeneity is primarily controlled by the geometry of depositional facies and sandbody continuity, which controls permeability structure. The permeability structure, in turn, has implications for CO₂ injectivity and near-term migration pathways, whereas the long-term sequestration capacity can be inferred from the production history. Examples of Gulf Coast oil and gas reservoirs with differing styles of stratigraphic heterogeneity demonstrate the impact of facies variability on fluid flow and CO₂ sequestration potential. Beach and barrier-island deposits in West Ranch field in southeast Texas are homogeneous and continuous. In contrast, Seeligson and Stratton fields in south Texas, examples of major heterogeneity in fluvial systems, are composed of discontinuous, channel-fill sandstones confined to narrow, sinuous belts. These heterogeneous deposits contain limited compartments for potential CO₂ storage, although CO₂ sequestration effectiveness may be enhanced by the high number of intraformational shale beds. These field examples demonstrate that areas for CO₂ storage can be optimized by assessing sites for enhanced oil and gas recovery in mature hydrocarbon provinces.     

Dawsonite fixation of mantle CO2 in the cretaceous Songliao Basin,Northeast China: a natural analogue for CO2 mineral trapping in oilfields

Abundant crude oil and CO₂ gas coexist in the fourth member of the Upper Cretaceous Quantou reservoir in the Huazijing Step of the southern Songliao Basin, China. Here, we present results of a petrographic characterization of this reservoir based on polarizing microscope, X-ray diffraction, fluid inclusion, and carbon–oxygen isotopic data. These data were used to identify whether CO₂ might be trapped in minerals after the termination of a CO₂-enhanced oil recovery (EOR) project, and to determine what effects might the presence of CO₂ have on the properties of crude oil in the reservoir. The crude oil reservoir in the study area, which coexists with mantle-derived CO₂, is hosted by dawsonite-bearing lithic arkoses and feldspathic litharenites. These sediments are characterized by a paragenetic sequence of clay, quartz overgrowth, first-generation calcite, dawsonite, second-generation calcite, and ankerite. The dawsonite analysed during this study exhibits δ¹³ C (Peedee Belemnite, PDB) values of ?4.97‰ to 0.67‰, which is indicative for the formation of magmatic–mantle CO₂. The paragenesis and compositions of fluid inclusions in the dawsonite-bearing sandstones record a sequence of two separate filling events, the first involving crude oil and the second involving magmatic–mantle CO₂. The presence of prolate primary hydrocarbon inclusions within the dawsonite indicates that these minerals precipitated from oil-bearing pore fluids at temperatures of 94–97°C, in turn suggesting that CO₂ could be stored as carbonate minerals after the termination of a CO₂-EOR project. In addition, the crude oil in the basin would become less dense after deposition of bitumen by deasphalting the injection of CO₂ gas into the oil pool.     

Site characterisation of a basin-scale CO<Subscript>2</Subscript> geological storage system: Gippsland Basin,southeast Australia

Geological storage of CO₂ in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO₂ emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO₂ per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO₂ storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO₂. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.     

Quick-look assessments to identify optimal CO2 EOR storage sites

A newly developed, multistage quick-look methodology allows for the efficient screening of an unmanageably large number of reservoirs to generate a workable set of sites that closely match the requirements for optimal CO₂ enhanced oil recovery (EOR) storage. The objective of the study is to quickly identify miscible CO₂ EOR candidates in areas that contain thousands of reservoirs and to estimate additional oil recovery and sequestration capacities of selected top options through dimensionless modeling and reservoir characterization. Quick-look assessments indicate that the CO₂ EOR resource potential along the US Gulf Coast is 4.7 billion barrels, and CO₂ sequestration capacity is 2.6 billion metric tons. In the first stage, oil reservoirs are screened and ranked in terms of technical and practical feasibility for miscible CO₂ EOR. The second stage provides quick estimates of CO₂ EOR potential and sequestration capacities. In the third stage, a dimensionless group model is applied to a selected set of sites to improve the estimates of oil recovery and storage potential using appropriate inputs for rock and fluid properties, disregarding reservoir architecture and sweep design. The fourth stage validates and refines the results by simulating flow in a model that describes the internal architecture and fluid distribution in the reservoir. The stated approach both saves time and allows more resources to be applied to the best candidate sites.     

Seal integrity and feasibility of CO<Subscript>2</Subscript> sequestration in the Teapot Dome EOR pilot: geomechanical site characterization

This paper reports a preliminary investigation of CO₂ sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO₂ leakage along reservoir-bounding faults. CO₂ injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO₂ EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO₂ injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO₂ column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO₂ injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.     

四川盆地理论CO_2地质利用与封存潜力评估

结合CO_2地质利用与封存技术机理,在国际权威潜力评估公式的基础上,系统地提出了适合中国地质背景的次盆地尺度CO_2封存潜力评估方法及关键参数取值。同时,以四川盆地为例,依次开展了枯竭油田地质封存与CO_2强化石油开采、枯竭气田与CO_2强化采气、不可采煤层地质封存与CO_2驱替煤层气,以及咸水层地质封存技术的CO_2地质封存潜力。结果表明,四川盆地利用深部咸水层与枯竭天然气田CO_2地质封存潜力最大,期望值分别达154.20×10~8t和53.73×10~8t。其中,枯竭天然气田因成藏条件好、勘探程度高、基础建设完善,为四川盆地及其周边利用枯竭气田CO_2地质封存技术实现低碳减排提供了早期示范机会。CO_2地质利用与封存潜力评估方法,对进一步开展全国次盆地尺度理论封存潜力评估与工程规划具有重要意义。     

松辽盆地含CO_2火山岩气藏的形成和分布

松辽盆地特有的深部构造背景和裂谷演化特征,造成盆地内含CO_2火山岩气藏的形成和富集。松辽裂谷盆地中新生代火山岩浆活动发育,总体上具有多期喷发、分布广泛和储集条件良好的特点。火山活动以中心式喷发为主,主要发育中基性-酸性火山岩,发育流纹岩、凝灰岩等多种岩石类型,爆发相和溢流相2种火山岩相。中生代火山岩在盆地内分布广泛,营域组构成深层有利储层,新生代火山岩在盆地外围出露较多,而在盆内出露较少。盆地高含量的二氧化碳为无机幔源成因,由青山口期和新生代幔源岩浆脱气形成。含CO_2火山岩气藏的形成主要受深部构造背景、深大断裂和中新生代火山岩控制。已发现含CO_2火山岩气藏主要分布于古中央隆起带及其两侧断陷的营城组火山岩中,具有点状、带状分布,局部富集的特点。根据主控因素分析,预测了5个CO_2富集区带。     

Spatial characterization of the location of potentially leaky wells penetrating a deep saline aquifer in a mature sedimentary basin

This work was motivated by considerations of potential leakage pathways for CO₂ injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO₂ injection, as defined by the spread of an injected CO₂ plume, varies from several hundred in high well-density areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available.