Controlling factors of remaining oil distribution after water flooding and enhanced oil recovery methods for fracturecavity carbonate reservoirs in Tahe Oilfield

Based on comprehensive analysis of core, well logging, seismic and production data, the multi-scale reservoir space, reservoir types, spatial shape and distribution of fractures and caves, and the configuration relationship with production wells in fracture-cavity carbonate reservoirs were studied systematically, the influence of them on the distribution of residual oil was analyzed, and the main controlling factors mode of residual oil distribution after water flooding was established. Enhanced oil recovery methods were studied considering the development practice of Tahe oilfield. Research shows that the main controlling factors of residual oil distribution after water flooding in fracture-cavity carbonate reservoirs can be classified into four categories: local high point, insufficient well control, flow channel shielding and weak hydrodynamic. It is a systematic project to improve oil recovery in fracture-cavity carbonate reservoirs. In the stage of natural depletion, production should be well regulated to prevent bottom water channeling. In the early stage of waterflooding, injection-production relationship should be constructed according to reservoir type, connectivity and spatial location to enhance control and producing degree of waterflooding and minimize remaining oil. In the middle and late stage, according to the main controlling factors and distribution characteristics of remaining oil after water flooding, remaining oil should be tapped precisely by making use of gravity differentiation and capillary force imbibition, enhancing well control, disturbing the flow field and so on. Meanwhile, backup technologies of reservoir stimulation, new injection media, intelligent optimization etc. should be developed, smooth shift from water injection to gas injection should be ensured to maximize oil recovery.

Discussion on the sweep efficiency of hybrid steam-chemical process in heavy oil reservoirs: An experimental study

Non-condensable gas(NCG),foam and surfactant are the three commonly-used additives in hybrid steam-chemical processes for heavy oil reservoirs.Their application can effectively control the steam injection profile and increase the sweep efficiency.In this paper,the methods of microscale visualized experiment and macroscale 3D experiment are applied to systematically evaluate the areal and vertical sweep efficiencies of different hybrid steam-chemical processes.First,a series of static tests are performed to evaluate the effect of different additives on heavy oil properties.Then,by a series of tests on the microscale visualized model,the areal sweep efficiencies of a baseline steam flooding process and different follow-up hybrid EOR processes are obtained from the collected 2D images.Specifically,they include the hybrid steam-N_(2)process,hybrid steam-N2/foam process,hybrid steam-surfactant process and hybrid steam-N2/foam/surfactant process(N2/foam slug first and steam-surfactant co-injection then).From the results of static tests and visualized micromodels,the pore scale EOR mechanisms and the difference between them can be discussed.For the vertical sweep efficiencies,a macroscale 3D experiment of steam flooding process and a follow-up hybrid EOR process is conducted.Thereafter,combing the macroscale 3D experiment and laboratory-scaled numerical simulation,the vertical and overall sweep efficiencies of different hybrid steam-chemical processes are evaluated.Results indicate that compared with a steam flooding process,the areal sweep efficiency of a hybrid steam-N2process is lower.It is caused by the high mobility ratio in a steam-N2-heavy oil system.By contrast,the enhancement of sweep efficiency by a hybrid steam-N2/foam/surfactant process is the highest.It is because of the high resistance capacity of NCG foam system and the performance of surfactant.Specifically,a surfactant can interact with the oil film in chief zone and reduce the interfacial energy,and thus the oil droplets/films formed during steam injection stage are unlocked.For NCG foam,it can plug the chief steam flow zone and thus the subsequent injected steam is re-directed.Simultaneously,from the collected 2D images,it is also observed that the reservoir microscopic heterogeneity can have an important effect on their sweep efficiencies.From the 3D experiment and laboratory-scaled numerical simulation,it is found that a N2/foam slug can increase the thermal front angle by about 150 and increase the vertical sweep efficiency by about 26%.Among the four processes,a multiple hybrid EOR process(steam-N2/foam/surfactant process) is recommended than the other ones.This paper provides a novel method to systematically evaluate the sweep efficiency of hybrid steam-chemical process and some new insights on the mechanisms of sweep efficiency enhancement are also addressed.It can benefit the expansion of hybrid steam-chemical processes in the post steamed heavy oil reservoirs.

Formation conditions and exploration direction of large natural gas reservoirs in the oil-prone Bohai Bay Basin, East China

The Bohai Bay Basin is a typical oil-prone basin, in which natural gas geological reserves have a small proportion. In this basin, the gas source rock is largely medium-deep lake mudstone with oil-prone type Ⅱ2-Ⅱ1 kerogens, and natural gas preservation conditions are poor due to active late tectonic movements. The formation conditions of large natural gas fields in the Bohai Bay Basin have been elusive. Based on the exploration results of Bohai Bay Basin and comparison with large gas fields in China and abroad, the formation conditions of conventional large-scale natural gas reservoirs in the Bohai Bay Basin were examined from accumulation dynamics, structure and sedimentation. The results show that the formation conditions of conventional large natural gas reservoirs in Bohai Bay Basin mainly include one core element and two key elements. The core factor is the strong sealing of Paleogene "quilt-like" overpressure mudstone. The two key factors include the rapid maturation and high-intensity gas generation of source rock in the late stage and large scale reservoir. On this basis, large-scale nature gas accumulation models in the Bohai Bay Basin have been worked out, including regional overpressure mudstone enriching model, local overpressure mudstone depleting model, sand-rich sedimentary subsag depleting model and late strongly-developed fault depleting model. It is found that Bozhong sag, northern Liaozhong sag and Banqiao sag have favorable conditions for the formation of large-scale natural gas reservoirs, and are worth exploring. The study results have important guidance for exploration of large scale natural gas reservoirs in the Bohai Bay Basin.

New empirical scaling equations for oil recovery by free fall gravity drainage in naturally fractured reservoirs

Gas-oil gravity drainage is a recognized major contributor to production in fractured reservoirs. While various empirical and analytical methods have been proposed to model this process, many of them contain assumptions that are questionable or require parameters that are not accessible at the field level. The aim of this work is to provide new, easy-to-use scaling equations for estimating the recoverable oil through gravity drainage in naturally fractured reservoirs, considering the effects of resistance capillary pressure. To accomplish this, data from four oilfields undergoing gravity drainage, including rock properties (eight sets), block height (three sets), and fluid properties (four sets), were used to generate a wide range of recovery curves using a single porosity numerical simulation model. Aronofsky's and Lambert's functions were then utilized to match the generated recovery curves. Statistical analysis revealed that the Aronofsky's function is more accurate in replicating the recovery patterns, while the Lambert's function tends to overestimate the early-time oil recovery and underestimate the oil recovery at a later stage in the majority of cases. A sensitivity analysis was subsequently performed, revealing that parameters such as absolute permeability, viscosity of oil, height of block, gas and oil density, characteristics of relative permeability and capillary pressure curves and interfacial tension (IFT) influence the amount of time taken to achieve the final recovery. Of these parameters, absolute permeability has the most significant effect on the amount of time needed to attain the final recovery, while the effect of difference between oil and gas densities is the lowest. Consequently, two different expressions were developed using nonlinear multiple regression analysis of simulated gravity drainage data which can be combined with the Aronofsky model to substitute the rate convergence constant. The new scaling equations include the effects of capillary pressure and other relevant factors in gravity drainage simulations. Both forms show satisfactory accuracy, as evidenced by the statistical parameters obtained (R2 = 0.99 and MSE = 0.0019 for both established correlations). The new correlations were verified using a wide range of oilfield data and are expected to provide a better understanding of the recovery process in naturally fractured reservoirs.

Prediction of oil recovery in naturally fractured reservoirs subjected to reinfiltration during gravity drainage using a new scaling equation

By comparing numerical simulation results of single-porosity and dual-porosity models,the significant effect of reinfiltration to naturally fractured reservoirs was confirmed.A new governing equation was proposed for oil drainage in a matrix block under the reinfiltration process.Utilizing inspectional analysis,a dimensionless equation suitable for scaling of recovery curves for matrix blocks under reinfiltration has been obtained.By the design of experiments,test cases with different rock and fluid properties were defined to confirm the scope of the presented equation.The defined cases were simulated using a realistic numerical simulation approach.This method can estimate the oil amount getting into the matrix block through reinfiltration,help simulate the oil drainage process in naturally fractured reservoirs accurately,and predict the recovery rate of matrix block in the early to middle periods of production.Using the defined scaling equation in the dual-porosity model can improve the accuracy of the predicted recovery rate.

Iterative coupling reservoir simulation on high performance computers

In this paper, the iterative coupling approach is proposed for applications to solving multiphase flow equation systems in reservoir simulation, as it provides a more flexible time-stepping strategy than existing approaches. The iterative method decouples the whole equation systems into pressure and saturation/concentration equations, and then solves them in sequence, implicitly and semi-implicitly. At each time step, a series of iterations are computed, which involve solving linearized equations using specific tolerances that are iteration dependent. Following convergence of subproblems, material balance is checked. Convergence of time steps is based on material balance errors. Key components of the iterative method include phase scaling for deriving a pressure equation and use of several advanced numerical techniques. The iterative model is implemented for parallel computing platforms and shows high parallel efficiency and scalability.

A multilevel preconditioner and its shared memory implementation for a new generation reservoir simulator

As a result of the interplay between advances in computer hardware, software, and algorithm, we are now in a new era of large-scale reservoir simulation, which focuses on accurate flow description, fine reservoir characterization, efficient nonlinear/linear solvers, and parallel implementation. In this paper, we discuss a multilevel preconditioner in a new-generation simulator and its implementation on multicore computers. This preconditioner relies on the method of subspace corrections to solve large-scale linear systems arising from fully implicit methods in reservoir simulations. We investigate the parallel efficiency and robustness of the proposed method by applying it to million-cell benchmark problems.

深层-超深层致密储层天然裂缝分布特征及发育规律

天然裂缝是深层-超深层致密储层的有效储集空间和主要渗流通道,影响着致密储层油气的运移、富集、单井产能、开发方式及开发效果。通过对近年来致密储层裂缝研究成果总结和文献综述,分析了深层-超深层致密储层天然裂缝分布特征及发育规律。将致密储层天然裂缝分为大尺度裂缝、中尺度裂缝、小尺度裂缝和微尺度裂缝4个级别。不同尺度裂缝分布具有幂律分布的特点,裂缝尺度越大,数量越少;裂缝尺度越小,数量越多。大、中尺度裂缝主要起渗流作用,小尺度裂缝主要起渗流和储集作用,而微尺度裂缝主要起储集作用。在地层埋藏过程中的应力体制演化决定了不同时期天然裂缝的类型、产状及其力学性质;构造应力大小、岩石力学层的力学性质和厚度差异控制了多尺度裂缝的形成分布及其发育程度。构造变形导致不同构造部位的局部应力和应变分布产生差异,增强了裂缝发育的非均质性。逆冲断层通过控制其上盘地层变形控制了“裂缝域”的分布规律;走滑断层的组合样式、活动方式和岩石力学层共同控制了相关裂缝的三维空间展布。裂缝形成演化过程中的开启-闭合规律决定了裂缝的储集空间,记录了裂缝有效性的演化历史。

地震叠后和叠前混合驱动下的页岩油储层多尺度裂缝预测方法

不同尺度、不同类型的天然裂缝的系统性表征有利于识别优质储层、改进开发效果.建立可靠的多尺度裂缝模型是提高页岩油储层钻遇率的重要依据,其关键在于精细预测小尺度裂缝的空间分布,指导钻井钻进和压裂过程.然而,基于地震属性的传统裂缝预测方法只能各自突出单一尺度的断裂,不同裂缝属性的数学独立性给综合裂缝系统的识别带来严峻挑战.我们提出一套改进的全尺度裂缝系统评估方案,其关键在于通过优化的各向异性蚁群裂缝识别算法确定小尺度裂缝的发育概率,将小尺度裂缝的发育概率与传统蚂蚁追踪产生的大尺度断层的概率进行融合,得到的综合裂缝系统可以实现全尺度裂缝的感知.详细的属性分析过程表明,方位各向异性能够精确描述微观裂缝特征.基于此,我们将各向异性分析得到的裂缝密度和裂缝走向融入蚁群追踪裂缝的各个阶段,在提高裂缝密集区搜索强度的同时,还对小断距裂缝的发育方向实现了精准刻画.针对页岩油藏的应用案例证明,根据改进方案得到的全尺度裂缝系统能够同时表征大尺度断层、小裂缝和裂缝破碎带的分布情况.研究区的成像测井结果进一步验证了小尺度裂缝预测发育方向的准确性及可靠性,能够为页岩油水平井开发部署提供理论指导.

沁水盆地南部中深部煤层气储层特征及开发技术对策

为了实现沁水盆地南部中深部煤层气高效开发,以郑庄北-沁南西区块为研究对象,基于参数井取心分析测试、注入/压降测试、地应力循环测试结果和大量动静态数据,通过与浅部对比,阐述了中深部煤储层特征,分析了从浅部到中深部煤层直井压裂和水平井分段压裂两种开发技术的改进,进而提出了中深部煤层气主体开发技术。结果表明,郑庄北-沁南西区块3号煤平均埋深1200 m左右,为中深部煤层气储层。随着埋深增加,研究区含气量和吸附时间均先增加后降低,含气量和吸附时间峰值分别位于埋深1100~1200 m和800~1000 m;随着埋深增加,研究区地应力场类型发生了2次转换,埋深小于600 m时,为逆断层型地应力场类型,水力压裂易形成水平缝,利于造长缝;埋深大于1000 m时为走滑断层型地应力场类型,水力压裂易形成垂直缝,裂缝延伸较短;埋深为600~1000 m时,地应力场由逆断层型向走滑断层型转换阶段,水力压裂形成的裂缝系统较为复杂。与浅层相比,中深部储层含气量、解吸效率和应力场发生明显转变。随着埋深增加,无论是直井(定向井)还是水平井,均应采用更大的压裂规模才能获得较好的效果。对于直井,埋深大于800 m后,压裂液量达到1500 m^(3)以上、排量12~15 m^(3)/min以上、砂比10%~14%以上,单井日产气量可以达到1000 m^(3)以上;对于水平井,埋深大于800 m后,压裂段间距控制在70~90 m以下,单段液量、砂量分别达到2000、150 m^(3)以上,排量达到15 m^(3)/min以上开发效果较好,单井产量突破18000 m^(3)。随着埋深增加,水平井开发方式明显优于直井,以二开全通径水平井井型结构、优质层段识别技术和大规模、大排量缝网压裂为核心的水平井开发方式是适用于沁水盆地南部中深部煤层气高效开发的主体工艺技术。

塔里木盆地库车山前超深气井砂垢堵塞成因及靶向解除技术

塔里盆地库车山前超深气田是西气东输主力气源地,具有超高温、超高压、高矿化度、储层裂缝非均质性强等特征,气井生产过程中砂垢堵塞问题突出,据统计最高影响气田产能达800×104 m^(3)/d。为实现超深气井高效解堵,通过气水两相结垢热力学预测模型、裂缝性储层岩石力学实验、井筒内气液固流动模拟等研究,揭示了超深气井砂垢复合堵塞成因,并形成了靶向解堵复产关键技术。研究结果表明:①“高温流动压降结垢、裂缝面破裂出砂”是超深气井出砂结垢的内在机理;②结垢固化松散砂桥形成复合堵塞是气井堵塞减产的主要原因,其中靶向除垢是解堵复产的关键所在;③靶向除垢解堵区域为井筒变径处和井周5 m内基质—裂缝系统,气井堵塞率30%~60%为最佳解堵时机;④非酸性除垢解堵液相比常用的酸性解堵液,在同级别溶垢能力的基础上,腐蚀速率降至0.49 g/(m^(2)·h),可同时满足低腐蚀和高效除垢的技术要求。结论认为,形成的超深气井靶向除垢解堵技术在塔里木盆地库车山前超深气田规模应用159井次,有效率达93.3%,累计增产天然气75.08×10^(8)m^(3),已成为西气东输主力气井快速解堵复产的“冬保良方”,可为国内外同类气田解堵复产提供技术借鉴。

四川盆地东部上石炭统黄龙组规模储层形成主控因素与发育模式

石炭系黄龙组是四川盆地东部地区(以下简称川东地区)重要的天然气产层之一,石炭系储层是控制气藏发育的关键因素。为了深入评价川东地区黄龙组储层,拓展勘探新领域,寻找接替区,在前人研究的基础上,应用大量钻井、岩心、露头和分析化验等资料,系统研究了黄龙组储层发育的主控因素和发育模式,并预测规模储层的展布。研究结果表明:(1)黄龙组储集岩主要为颗粒白云岩、角砾白云岩和晶粒白云岩,储集空间主要为晶间孔/晶间溶孔、粒间溶孔/粒内溶孔、溶洞和裂缝,颗粒滩为有利储集体,裂缝-溶蚀孔洞型储层质量好;(2)储层发育主要受乐山—龙女寺古隆起和开江古隆起、沉积作用及成岩作用的共同控制,古隆起控制颗粒滩分布和准同生期成岩作用,是规模成储的基础,准同生期白云石化作用、层间岩溶和风化壳岩溶作用的叠加是形成规模储层的关键,喜马拉雅构造运动产生大量构造裂缝,提高了储层的渗滤性和规模性;(3)一定厚度和较大面积的Ⅰ—Ⅲ类储层可形成规模储层区,对5个规模储层发育区进行了评价,已发现气藏主要分布在这5个区域的背斜构造部位。结论认为,川东地区石炭系仍有较大的天然气勘探开发潜力,向斜区发育大面积的规模储层,是下一步天然气增储上产的重要方向。

页岩气勘探开发实验技术研究进展与发展方向

页岩气开发的成功得益于全新地质理论的建立及工程技术的进步,其中地质理论的创新离不开实验技术的突破与发展,但随着页岩气进入全面开发的新阶段,对实验方法、基础理论等方面提出了更高要求和技术挑战。为此,针对页岩气勘探开发过程中的关键问题,从页岩矿物组成、岩石物性、孔隙结构、含气性及可压性等5个方面展示了地质实验研究的进展和应用实例,分析了页岩气勘探开发实验研究面临的问题和挑战,并展望了其未来的发展方向和趋势。研究结果表明:①薄片鉴定和X射线衍射是页岩矿物分析最有效的定性定量方法,开展矿物成因实验研究对于揭示页岩成储规律及地质工程甜点段优选有着更重要的指导意义;②页岩物性测试方法多且标准不统一,需要根据研究目的选择适用的测试方法,开展地层条件下的物性测试对储量计算及开发效果评价更有帮助;③页岩孔隙结构表征已形成了从宏观到微观、从定性到定量、从二维到三维的综合评价方法,可指导开发层系划分和水平井靶窗优选;④页岩含气性评价已形成了现场含气量测试、等温吸附、气体碳同位素监测等实验方法,揭示了页岩气赋存状态和解吸规律,可有效指导气井生产制度制订和采收率提高;⑤页岩可压性评价已形成了X射线衍射、多尺度的裂缝网络刻画、三轴力学、差应变法、声波各向异性法及声发射法等实验方法,可指导水平井设计和压裂工艺优化。结论认为,建立跨尺度多方法深度融合的实验体系、加强原位条件下的页岩气储层评价、开展关键参数的动态演化和基于大数据模型的人工智能实验评价等是下一步研究方向,持续完善页岩气实验地质技术体系方可为页岩气高效勘探开发提供更好的理论基础和技术支撑。

深层煤岩气压裂研究进展与展望

中国深层煤岩气资源丰富,勘探开发潜力巨大。水力压裂是开发深层煤岩气的重要工程技术,目前深层煤岩气水力压裂仍然存在技术瓶颈,在一定程度上制约了深层煤岩气的勘探开发。为进一步明确深层煤岩气水力压裂技术现状和发展趋势,基于鄂尔多斯盆地和沁水盆地深层煤岩气勘探开发案例,分析了深层煤岩气压裂地质特征的特殊性,论述了深层煤岩气压裂工程技术现状,剖析了深层煤岩气压裂存在的理论与技术挑战,最后展望了压裂改造理论与技术发展方向。研究结果表明:①与中深层页岩、低渗透致密砂岩和浅层煤层相比,深层煤岩具有更复杂的裂缝和割理裂隙网络系统,具有低孔低渗、煤体结构完整、高地应力、高弹性模量、低泊松比的特征,这些地质特征差异使得深层煤岩对应的压裂改造技术内涵应有差异;②深层煤岩主流压裂改造主体技术为水平井超大规模极限体积压裂和多轮次转向缝网弥合压裂;③下一步需持续研究不同煤阶、不同地域的深层煤岩气压裂地质特征差异性、压裂裂缝起裂及延伸规律、低成本压裂材料、高效压裂工艺技术。结论认为,深层煤岩气压裂改造开发需要结合压裂地质特征构建多尺度地质模型,建立“地质-工程”双甜点预测模型,并大力发展低成本、环境友好的压裂材料及工艺配套技术,进而实现深层煤岩气的规模效益开发。

川西须二气藏产水气井合理配产方案探讨

川西须二气藏储层致密,气井普遍产水,且断缝体规模和水体强度差异大,渗流机理复杂,使得单一产能模型和配产方法适用性差。综合因素导致气井合理配产方案不明确,从而制约了气藏的规模生产和效益开发。文中建立了考虑启动压力梯度、应力敏感等影响的气井气水两相产能评价模型,结合采气指示曲线法、动态分析法、无阻流量法及数学统计法,分别探讨了不同断缝体规模、不同水体强度及综合考虑2种因素影响的气井合理配产方案,须二气藏开发实践证实了其有效性和可靠性。此外,气井配产量与断缝体规模和水体强度的相关性明显,整体表现为裂缝越发育,配产量越高,配产比越低;水体强度越高,配产量越低,配产比也越小。该研究对川西须二气藏气井的合理工作制度制定与气井稳定生产具有较大的实际价值。

超深层裂缝性致密砂岩气藏多尺度耦合流动数值模拟

塔里木盆地克拉苏气田白垩系气藏是罕见的超深层裂缝性致密砂岩气藏,该类气藏的储渗空间具有显著的多尺度特征,基质与多尺度裂缝、断层介质的渗透率级差相差5~6个数量级,常规渗流理论难以准确描述其流动规律和开发机理。为此,基于单裂缝流动物理实验结果及流体力学理论,结合多尺度裂缝几何信息,应用均化理论和体积平均尺度升级方法,将多尺度介质划分为5个流动系统,建立了考虑介质间的非稳态窜流多尺度耦合流动数学模型,并应用有限体积法对耦合流动模型进行了数值求解和数值试井分析。研究结果表明:(1)不同尺度裂缝中具有不同的流动特征,随缝宽增加流速加快,流动模态发生变化;(2)多尺度耦合流动模型与双重介质模型结果存在较大差异,导数曲线具有不同趋势特征;(3)应用所建立的多尺度耦合流动模型成功解释了气藏实际试井数据,模型能够反映实际地层中的流动过程。结论认为,超深层裂缝性致密砂岩气藏多尺度耦合流动模型揭示了多尺度裂缝以及致密基质间逐级动用、协同供气的开发机理,可为类似气藏制订合理开发技术政策及气藏提高采收率提供理论和技术支撑。

基于VIC模型的三峡库区流域小时尺度实时洪水预报

VIC模型在流域面积大于3 000 km^(2)的大型流域日或月尺度洪水模拟中表现出良好的适用性,而在大型流域小时尺度实时洪水预报过程中的适用性尚未得到验证。以三峡库区大型流域为例,通过建立小时尺度VIC分布式洪水预报模型,构建三峡库区流域实时滚动洪水预报方案,将VIC分布式洪水预报模型实地化部署并应用于2022及2023年三峡库区实时洪水预报。结果表明:VIC模型应用于2014—2021年三峡库区各子流域历史洪水模拟,率定期和验证期的洪量、洪峰平均合格率均在80%以上,确定性系数均值在0.70以上,构建的VIC分布式洪水预报模型在三峡库区及其子流域洪水模拟中表现出良好的适用性;在2022及2023年三峡库区4场典型洪水的实时洪水预报中,径流深和洪峰的平均相对误差达到16.3%和5.0%,重点产流区产流量平均相对误差为7.8%,能够准确把握库区重点产流区的洪量及来水过程,因此VIC模型在大型流域小时尺度实时洪水预报中具有较大的应用潜力。

闽江流域多时间尺度降雨—径流关系变化与成因

为进一步揭示闽江流域降雨—径流关系的时空变化规律,识别主要驱动因子,基于1960—2019年降雨和径流数据,应用TFPW—MK方法,按照年以及年内的汛期与非汛期、前汛期和后汛期、最大月和最小月等不同时间尺度,检测闽江上游三大支流、干流及全流域等空间尺度的降雨—径流演变趋势;结合Sen trend方法,从气候变化、土地利用和水库工程建设3方面,分析影响降雨—径流关系变化的成因。结果表明:1)闽江流域及各支流年降雨—径流均呈不显著上升,趋势变化一致;2)除支流建溪流域,闽江及其他支流非汛期降雨—径流上升趋势显著;汛期内部趋势变化分化明显,前汛期降雨—径流略减少,后汛期降雨—径流大部分显著增加;3)极端降雨—径流的变化趋势不一致,主要受大型水库工程建设的影响。基于多时间尺度的分析,更深入揭示闽江流域降水、径流的演变及气候变化与人类活动的影响,对区域水资源管理与水土保持具有重要参考价值。

极端天气下三峡库区土地利用对河流水质的多时空尺度影响

为探究极端天气下流域内水质对土地利用的响应关系,本研究基于不同空间尺度(1000 m河段缓冲区、500 m河岸带缓冲区及子流域)的土地利用指数以及旱季(2019年11月)、雨季-洪水期(2020年7月)和雨季-干旱期(2022年8月)的水质数据,探究流域内土地利用对水质的多时空尺度影响,从而得到保护流域水质和规划流域内土地利用格局的最佳时空尺度和对水质影响最显著的预测因子。研究表明:(1)流域水质受极端天气影响,降雨会增强水体的稀释能力,高温会加快水中微生物反应速率,具体表现为雨季-洪水期的水质较好,雨季-干旱期次之,旱季较差。(2)土地利用对水质指标的影响存在时空尺度效应,土地利用在子流域和旱季尺度下对河流水质影响最显著。(3)不同土地利用指数对流域水质影响存在差异,耕地、林地、斑块密度、最大斑块指数和边缘密度是影响水质指标最显著的解释变量。其中林地与多数水质指标具有负相关关系,建设用地、耕地、斑块密度与较多水质指标存在正相关关系。本研究结果为合理规划土地利用格局以及保护河流水质提供科学依据,对三峡库区环境可持续发展及生态保护具有一定意义。

三峡库区多时空尺度土地利用和景观格局对水质的影响

为了探究三峡库区水质对不同尺度的土地利用和景观格局的响应,基于三峡库区2019—2021年7个断面的水文与水质数据和2020年土地利用数据,分析了水质时空异质性、多尺度河岸带缓冲区内土地利用和景观格局特征,同时利用相关性分析和冗余分析(RDA)确定了土地利用和景观格局对水质指标的影响及最佳影响尺度,并采用偏最小二乘回归(PLSR)探究了最佳影响尺度下的关键影响因子。结果表明:三峡库区水质状况整体稳定,枯水期的水质优于丰水期,水质状况主要受到面源污染、支流汇入、磷矿产业和城镇化的影响;小尺度缓冲区内景观斑块破碎化较严重,但多样性较高,耕地是库区的优势景观类型,其破碎化程度的增加有利于水环境的改善;林地和草地在枯水期对水环境的净化作用优于丰水期,而水域是河流氮磷污染物的主要来源;整体上土地利用和景观格局对水质指标的解释能力在丰水期高于枯水期,且在300 m缓冲区尺度下解释能力最强,其中耕地、草地、水域和斑块密度(PD)是影响水质指标的关键变量。