基于竞争吸附的页岩气藏提高采收率机理

为研究注CO₂提高页岩气藏采收率的机理以及确定合理的注入参数,以页岩吸附解吸实验为基础,对比了页岩自然降压开采和在不同注入压力、注入速率下注CO₂开采页岩气藏的实验结果,研究了降压开采和注CO₂开采2种方式下CH₄的采气速率和采收率的变化。结果表明,在相同实验条件下,CO₂吸附能力最强,CH₄次之,N₂最弱,N₂解吸能力最强,CH₄次之,CO₂最弱;3种气体的等温解吸曲线相对于等温吸附曲线均存在一定的滞后,CO₂的滞后现象最为明显;降压开采的采收率较低,注CO₂可以有效提高CH₄的采气速率,延长稳产时间,使累计产气量快速增长;在一定注入压力和注入速率范围内,CH₄采收率随着CO₂注入压力和注入速率的增加而增加,但其增加幅度因岩心孔隙度和渗透率的不同而有所不同。     

人工裂缝参数对CO2-ESGR中CO2封存和CH4开采的影响

目的 页岩储层中的裂缝系统对CH₄产量和CO₂封存量有着重要的影响,不同的储层地质特征有其对应的最优压裂方案。对鄂尔多斯盆地延长组页岩储层人工裂缝参数对CO₂封存和CH₄开采的影响进行分析。方法 基于鄂尔多斯盆地延长组页岩储层地质条件建立了页岩基质-裂缝双孔双渗均质模型,分析CO₂增强页岩气开采技术(CO₂-ESGR)中人工裂缝半长、裂缝宽度、裂缝高度、裂缝间距和裂缝数量对CO₂封存量和CH₄产量的影响。结果 CO₂封存量和CH₄产量与裂缝半长、裂缝宽度和裂缝高度呈正相关,其中裂缝宽度的影响最大,从5 mm增加到25 mm时,最多可使CO₂封存量和CH₄产量分别增加112.69%和87.11%。裂缝间距和裂缝数量增加可提高CO₂封存量和CH₄产量,但水平井长度相同时裂缝数量增加对CO...     

页岩注入超临界CO2渗流及增透实验

以四川省长宁县双河镇燕子村龙马溪组页岩为研究对象,采用自行研制的三轴渗流装置,开展了考虑注入压力和体积应力影响的页岩中超临界CO₂渗流及增透规律实验研究。结果表明：页岩中超临界CO₂渗透率随着孔隙压力增大呈现先减小后增大趋势,当孔隙压力较小时存在Klinkenberg效应;随体积应力的增大渗透率逐渐减小,曲线基本呈现负指数变化规律。开展不同增透条件下页岩中CH₄渗流实验,宏观量化分析超临界CO₂注入压力对于页岩增透效果的影响,可以得出随着超临界CO₂注入压力的增加,CH₄渗透率呈现上升趋势,但增长幅度先上升后下降,即超临界CO₂注入压力为9.5MPa时增透效果最为明显。通过微观分析页岩元素含量得出超临界CO₂可以萃取和溶解页岩中的O、Ca、Mg等矿物元素,有效促进页岩内部微孔隙的发育,致使页岩渗透能力增强。     

高—过成熟页岩CH4/N2/CO2混合气体竞争吸附特征与地质意义

为研究高—过成熟页岩对N₂、CH₄及CO₂混合气体的竞争吸附特征及其地质意义,通过混合气体吸附—解吸装置,结合穿透曲线法,对四川盆地周缘NY?1井龙马溪组1 420.90 m、1 422.75 m、1 423.75 m和牛蹄塘组2 261.53 m、2 265.80 m、2 268.37 m 6个深度的岩样,开展了20 ℃、注气压力0.25 MPa条件下N₂、CH₄和CO₂等比例混合气体的竞争吸附实验,得到了各岩样对混合气体的竞争吸附规律;并通过低温N₂和CO₂吸附法,分析了6个岩样的孔隙结构,探究了其对竞争吸附的影响。结果表明：龙马溪组页岩中N₂出口端浓度有超过初始浓度的现象,而牛蹄塘组页岩中N₂、CH₄和CO₂出口端浓度均未超过初始浓度;实验结果与Yoon?Nelson模型拟合结果较好,R²值可达0.9以上,各岩样吸附速率常数均有N₂>CH₄>CO₂的规律,故N₂相较CH₄和CO₂可先被样品吸附,随后吸附速率慢的CH₄和CO₂被吸附,岩样对2种气体吸附选择性更强,所以将N₂置换出,导致龙马溪组岩样N₂出口端浓度超过初始浓度;龙马溪组岩样中微孔发育程度较高,孔径小、比表面积大、吸附能力强,能更好地吸附CH₄和CO₂这2种吸附选择性强的气体,使得已吸附的N₂被置换出,从而造成游离气中N₂浓度增加。实验结论为我国页岩气勘探开发提供了理论依据,同时对部分地区页岩气组分中N₂的成因具有一定指导意义。     

CH4- CO2体系固体CO2形成条件的预测模型

采用膨胀机制冷工艺回收天然气中的乙烷时,膨胀机出口与脱甲烷塔顶部的温度较低,容易发生CO₂冻堵,影响装置的正常运行。准确预测固体CO₂的形成条件,有助于及时采取相应的措施调整凝液回收装置的操作工况,避免CO₂冻堵。为此,分析了CO₂固体的形成条件,根据相平衡原理,采用标准形式的Peng Robinson状态方程建立了液固平衡模型（LSE）和气固平衡模型（VSE）,据此分别对CH₄-CO₂2气相体系和CH₄-CO₂2液相体系中的固体CO₂形成温度进行了计算,并与用HYSYS软件预测的固体CO₂形成温度进行了比较。结果表明：该计算模型的准确度较高,与实验数据的误差在2 ℃以内;而HYSYS软件预测的CH₄-CO₂气相体系的固体CO₂形成温度较实验数据偏高1～5 ℃,预测的CH₄-CO₂液相体系的固体CO₂形成温度较实验数据偏低1～6 ℃。     

等离子体催化重整CH4/CO2中的等离子体强化表面反应动力学研究

采用实验测量和模拟预测相结合的方法，通过构建详细的机理并开展零维动力学模拟，研究等离子体催化CH₄/CO₂重整过程中等离子体活性物质对表面反应动力学的强化效应。结果表明：等离子体与催化剂的协同对CH₄和CO₂的活化转化能力远强于纯等离子体；动力学模型对反应物的消耗和产物的生成具有较好的预测能力；活性自由基与吸附态物质之间的E-R反应具有较高的反应活性，能有效改变并促进表面反应路径，如等离子体强化的E-R反应CH₃(s)+O→CH₃O(s)的速率比相应的吸附态物质之间的L-H反应CH₃(s)+O(s)→CH₃O(s)+Ni(s)的速率高4个数量级；等离子体催化CH₄/CO₂重整过程中的表面反应路径主要以气相物质与表面吸附态物质之间的E-R反应为主。     

四川盆地龙马溪组页岩的CH4和CO2气体高压吸附特征及控制因素

通过对四川盆地重庆地区下志留统龙马溪组的钻井岩心和野外露头等进行分析,利用高压吸附仪分析了页岩中CH₄、CO₂气体的吸附性能,并采用N₂吸附法、CO₂吸附法、场发射扫描电子显微镜(FE_SEM)和X-射线衍射(XRD)等技术,从孔隙结构、有机碳含量、矿物成分、温度和单位压力变化等方面探讨页岩吸附能力的影响关系。研究表明,龙马溪组页岩CH₄、CO₂吸附曲线具有Ⅰ型等温线特征,用Langmuir模型回归等温线能较好地拟合实验数据;页岩的总孔体积、比表面积与饱和吸附量体现良好的线性相关关系,且正相关;页岩有机质和矿物成分通过控制着微米_纳米级孔隙的相对丰度影响着气体的吸附和储存,微孔、中孔孔体积及孔隙度均随总有机碳含量(TOC)值增加而增大;TOC值越大,页岩的饱和吸附量就越大,二者具有良好的正相关性;吸附气量与黏土矿物含量呈正线性相关,与脆性矿物含量呈现相反的变化规律。温度升高会加快气体解吸速度,降低吸附量;此外,页岩对CO₂吸附能力高于CH₄。     

气藏中CO2封存过程气水互溶特性实验研究

利用PVT装置开展了不同CO₂ 含量下CO₂ —烃—水体系在不同条件下气水互溶特性实验,研究气藏注CO₂ 封存过程中CO₂ —烃—水体系互溶规律。结果表明,相同温度压力下,随CO₂ 的不断注入,气相中CO₂ 含量和水蒸汽含量不断增加,液相中CO₂  在水中的溶解度越大,CH₄ 溶解度越小,地层条件下CO 含量为68％物质的量的气样比CO₂ 含量为23％物质的量的气样的CO₂ 溶解度增加1.116％物质的量,而CH₄ 的溶解度减小0.13％ 物质的量。CO₂ 和CH₄ 在水中的溶解度均随压力升高而增大,随温度升高而减小;在CO₂  临界点附近,CO₂ 在水中的溶解度变化显著,40℃下CO₂ 含量为23％物质的量的气样的CO₂ 溶解度6～9MPa增加了0．138％ 物质的量,而9—12 MPa仅增加0.092％ 物质的量,且压力越大增加量越小。高温低压时受水蒸发作用影响,气相中CO₂  及CH₄ 含量随温度升高急剧降低,随压力升高缓慢上升,当压力高18MPa后,气相中CO₂及CH₄ 含量基本保持不变。     

CO2和CH4的转化与气田的关系之我见

长期以来，在石油地质研究领域对CO₂与CH₄的转化关系及其转化成因尚无统一的定论。一般只将CO₂作为生油还原环境的参数指标之一。因此在油气田勘探研究中，常将CO₂在储存空间的保存完好性作为判定生、储油气层保存完好性的指标，这样CO₂在油气田勘探阶段中仅作为寻找油气藏的一个线索。但在如下几种条件：①存在CO₂催化剂（触媒剂）；②存在H₂及H₂的化合物；③具备一定的温度和压力条件；④处于特定的保存条件下，则CO₂可以转化为CH₄及烃类，或者CH₄及烃类能够转化为CO₂。由此认为，CO₂可作为勘探开发大气田的指示气体，而且在发现有高含量和高产量的CO₂气井地区内，有可能勘探到丰富的天然气资源。     

含CO2天然气燃烧爆炸特性实验研究

我国已开始开发含CO₂酸性天然气气田,此类气田的开发要求同时重视天然气的火灾爆炸特性和CO₂的窒息危险性,如何确定CO₂含量阈值浓度,从而制订相应的防护措施具有重要现实意义。为此,运用实验手段研究了含CO₂天然气的爆炸极限,得到了CH₄、空气及CO₂三种组分气体爆炸范围图。研究表明：当泄漏天然气与空气的混合物中CO₂体积分数达到13.86%,CH₄体积分数为7.48%时,CH₄在此混合气体中的爆炸下限与上限重合。当泄漏天然气与周围空气的混合物中CO₂体积分数超过13.86%时,应重点考虑CO₂的窒息危害,而在此浓度以下时,则应着重考虑天然气的火灾爆炸危险性。同时,还针对气田安全生产的实际情况提出了相应的对策措施。     

Sequestering carbon dioxide in a closed underground volume

The capture and subsequent geologic sequestration of CO₂ has been central to plans for managing CO₂ produced by the combustion of fossil fuels. The magnitude of the task is overwhelming in both physical needs and cost, and it entails several components including capture, gathering and injection. The rate of injection per well and the cumulative volume of injection in a particular geologic formation are critical elements of the process.Published reports on the potential for sequestration fail to address the necessity of storing CO₂ in a closed system. Our calculations suggest that the volume of liquid or supercritical CO₂ to be disposed cannot exceed more than about 1% of pore space. This will require from 5 to 20 times more underground reservoir volume than has been envisioned by many, and it renders geologic sequestration of CO₂ a profoundly non-feasible option for the management of CO₂ emissions.Material balance modeling shows that CO₂ injection in the liquid stage (larger mass) obeys an analog of the single phase, liquid material balance, long-established in the petroleum industry for forecasting undersaturated oil recovery. The total volume that can be stored is a function of the initial reservoir pressure, the fracturing pressure of the formation or an adjoining layer, and CO₂ and water compressibility and mobility values.Further, published injection rates, based on displacement mechanisms assuming open aquifer conditions are totally erroneous because they fail to reconcile the fundamental difference between steady state, where the injection rate is constant, and pseudo-steady state where the injection rate will undergo exponential decline if the injection pressure exceeds an allowable value. A limited aquifer indicates a far larger number of required injection wells for a given mass of CO₂ to be sequestered and/or a far larger reservoir volume than the former.     

超破裂压力注气开发煤层甲烷探讨

中国大多数煤层气藏具有低压、低渗、低饱和等特点，采用常规增产改造和降压开发技术难于奏效。文章提出了超破裂压力注气技术开发该类低渗煤层气藏的设想，将一次开采与增产改造、提高采收率紧密结合，在开发初期即实施提高采收率措施。研究表明，煤层甲烷解吸-扩散-渗流过程受多种因素影响，在煤层气开发中，一方面需要提高煤层渗透率，另一方面还必须促进甲烷高效快速解吸。超破裂压力注气开发煤层甲烷的机理主要包括降低甲烷分压诱发甲烷解吸，通过竞争吸附置换解吸甲烷，诱发微裂隙形成和天然裂缝延伸，补充能量，防止裂缝闭合和水相圈闭，降低应力敏感损害。超破裂压力注气方式包括注气吞吐和气驱，注气吞吐适用于单井开发，气驱则要形成注采井网。要针对注气开发煤层气特点，选用合理的注气和完井方式，形成注气开发煤层气配套技术，提高煤层甲烷产量和采收率。     

Enhanced Natural Gas and Condensate Recovery by Carbon Dioxide and Methane Flooding

Abstract

The authors quantitatively investigates the recovery efficiency, pattern behavior, and relative permeability of (a) condensate following supercritical carbon dioxide (CO₂) injection, methane (CH₄) injection, and the injection of their mixtures; and (b) natural gas of various compositions following pure supercritical CO₂ injection. A high-pressure high-temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores. This work is part of an integrated enhanced natural gas and condensate recovery project conducted for a local reservoir in Western Australia. This data will help the operators develop operational and design strategies for their present and future EOR projects.     

浅层油藏稠油热水/CO2驱油效率实验模拟研究

新疆油田九_6区齐古组浅层稠油油藏已进入蒸汽开采中后期,油藏开采经历了蒸汽吞吐、加密调整、蒸汽驱过程,采出程度为37%。现阶段单一蒸汽驱效果明显下降,地层亏空严重,蒸汽热利用效率低,吸汽不均,波及程度差异大,油水流度比大,采收率低。热水复合CO_2驱油充分利用热水热效应和发挥CO_2溶解降黏等作用,是提高原油采收率的有效方法。因此,针对九_6区稠油开展不同混合方式热水/CO_2驱油模拟实验,分别研究了纯热水驱、热水与CO_2混注、热水与CO_2段塞的驱油效率。结果表明,纯热水驱累积驱油效率为49.19%,热水/CO_2混注累积驱油效率最大为71.25%,段塞驱累积驱油效率高达85.96%。同时,分析了驱出原油及岩心残余油组分变化。     

Evaluation of miscible and immiscible CO2 injection in one of the Iranian oil fields

Carbon dioxide (CO₂) flooding is one of the most important methods for enhanced oil recovery (EOR) because it not only increases oil recovery efficiency but also causes a reduction of greenhouse gas emissions. It is a very complex system, involving phase behavior that could increase the recovery of oil by means of swelling, evaporation and decreasing viscosity of the oil. In this study, a reservoir modeling approach was used to evaluate immiscible and miscible CO₂ flooding in a fractured oil field. To reduce simulation time, we grouped fluid components into 10 pseudo-components. The 3-parameter, Peng–Robinson Equation of State (EOS) was used to match PVT experimental data by using the PVTi software. A one-dimensional slim-tube model was defined using ECLIPSE 300 software to determine the minimum miscibility pressure (MMP) for injection of CO₂. We used FloGrid software for making a reservoir static model and the reservoir model was calibrated using manual and assisted history matching methods. Then various scenarios of natural depletion, immiscible and miscible CO₂ injection have been simulated by ECLIPSE 300 software and then the simulation results of scenarios have been compared. Investigation of simulation results shows that the oil recovery factor in miscible CO₂ injection scenario is more than other methods.     

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.     

Investigation of immiscible CO2 and C1 injection and comparison with water injection for enhanced oil recovery in naturally fractured reservoirs

Reservoir oil and gas content tends to rise up to the surface as long as their potential energy levels are sufficient. In order to amplify this energy, either during the time when oil is uprising on its inherent energy or since after, so as to facilitate the traveling of oil to the surface, enhanced oil recovery (EOR) methods come into play. Furthermore, the increasing demand for oil from one hand, and the shrinkage of producible reserves on the other hand, have made it unavoidable to undertake EOR techniques. Built in this research was a 10-element model of reservoir fluid to simulate its behavior. Furthermore, slim tube simulation was undertaken to determine minimum miscibility pressure for various gases. Then, different scenarios of natural depletion, CO₂ injection, methane injection, and water injection were simulated by ECLIPSE 300 software package with the results of different scenarios compared. The results indicated water injection to be associated with higher recovery factor.     

Black Oil and Compositional Reservoir Simulation for Increasing the Recovery Performance of an Iranian Fractured Carbonate Reservoir

Abstract

Naturally fractured reservoirs contain a significant amount of world oil reserves. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important, challenging, and computationally intensive problems in reservoir engineering. Black oil and compositional reservoir simulators have been used to determine the reservoir management and production strategies to increase the oil recovery from a low-porosity, low-permeability fractured carbonate reservoir, with an average matrix permeability of 0.8 md, average fracture permeability of 500 md, and an average matrix porosity of 10%. This reservoir is a candidate for an enhanced oil recovery (EOR) process, because the reservoir production rate has been declined due to increasing the water cut as a result of rising the water oil contact. The injection techniques that have been considered in this study for black oil model include (a) gas injection, (b) water injection, and (c) simultaneous water alternating gas injection and for the compositional model include (a) dry gas injection, (b) CO₂ injection, and (c) N₂ injection. Simulation results show that CO₂ injection has the maximum oil recovery between the EOR scenarios.     

Laboratory investigation of carbon dioxide separation from methane using a PES/Pebax 1657 composite membrane

Removal of carbon dioxide from methane is a critical issue in the gas sweetening and treatment units. The aim of this study is to investigate the capability of PES/Pebax composite membrane in order to CO₂ removal from the CH₄. In this regard, permeability values of both carbon dioxide and methane have been measured. The ranges of temperature and pressure used for pure gases experiments were 20–50°C and 2.5–10 bar, respectively. Moreover, influence of CO₂ concentration on the CH₄ permeability and its selectivity was studied. Results indicated that the pressure and temperature have significant influence on permeability and selectivity. In addition, for the gas mixtures, experiments were carried out at 5 bar and 35°C. Results also indicated that at higher CO₂ concentrations the CO₂ permeability increased significantly.     

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.