Flowback and early-time production modeling of unconventional gas wells using an improved semi-analytical method

Multiple fractured horizontal wells (MFHWs) currently are the only possible means of commercial production from the low and ultra-low permeability unconventional gas reservoirs. In early production time, flowback fluid, which constitutes of hydraulic water and gas flow within fractures, is collected and analyzed. Flowback analysis has been shown to be a useful tool to estimate key properties of the hydraulic fracture such as conductivity and pore volume. Until date, most tools of flowback analysis rely on empirical and approximate methods. This study presents an improved Green-function-based semi-analytical solution for performance analysis of horizontal gas wells during flowback and early production periods. The proposed solution is derived based on coupling the solutions of two domains: a rigorously derived Green’s function-based integral solution for single-phase gas flow in matrix, and a finite-difference, multiphase solution for gas–water two-phase flow in the fracture. The validity of proposed semi-analytical solution is verified by finely gridded numerical models built in a commercial simulator for a series of synthetic cases considering a variety of fluid and reservoir property combinations, as well as various different production constraints. Comparisons against available empirical and approximate methods are also provided for these cases.

Effect of fracture fluid flowback on shale microfractures using CT scanning

The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs.At the early stage of flowback,there is no single-phase flow of the liquid phase in shale,but rather a gas-water two-phase flow,such that the single-phase flow model for tight oil and gas reservoirs is not applicable.In this study,pores and microfractures are extracted based on the experimental results of computed tomography(CT)scanning,and a spatial model of microfractures is established.Then,the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law,which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness.The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method(LBM).The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures,which explains the low fracturing fluid flowback rate in shale hydraulic fracturing.

Evaluating the stability and volumetric flowback rate of proppant packs in hydraulic fractures using the lattice Boltzmann-discrete element coupling method

The stability and mobility of proppant packs in hydraulic fractures during hydrocarbon production are numerically investigated by the lattice Boltzmann-discrete element coupling method(LB-DEM).This study starts with a preliminary proppant settling test,from which a solid volume fraction of 0.575 is calibrated for the proppant pack in the fracture.In the established workflow to investigate proppant flowback,a displacement is applied to the fracture surfaces to compact the generated proppant pack as well as further mimicking proppant embedment under closure stress.When a pressure gradient is applied to drive the fluid-particle flow,a critical aperture-to-diameter ratio of 4 is observed,above which the proppant pack would collapse.The results also show that the volumetric proppant flowback rate increases quadratically with the fracture aperture,while a linear variation between the particle flux and the pressure gradient is exhibited for a fixed fracture aperture.The research outcome contributes towards an improved understanding of proppant flowback in hydraulic fractures,which also supports an optimised proppant size selection for hydraulic fracturing operations.

Evaluation and Application of Flowback Effect in Deep Shale Gas Wells

The pivotal areas for the extensive and effective exploitation of shale gas in the Southern Sichuan Basin have recently transitioned from mid-deep layers to deep layers.Given challenges such as intricate data analysis,absence of effective assessment methodologies,real-time control strategies,and scarce knowledge of the factors influencing deep gas wells in the so-called flowback stage,a comprehensive study was undertaken on over 160 deep gas wells in Luzhou block utilizing linear flow models and advanced big data analytics techniques.The research results show that:(1)The flowback stage of a deep gas well presents the characteristics of late gas channeling,high flowback rate after gas channeling,low 30-day flowback rate,and high flowback rate corresponding to peak production;(2)The comprehensive parameter AcmKm1/2 in the flowback stage exhibits a strong correlation with the Estimated Ultimate Recovery(EUR),allowing for the establishment of a standardized chart to evaluate EUR classification in typical shale gas wells during this stage.This enables quantitative assessment of gas well EUR,providing valuable insights into production potential and performance;(3)The spacing range and the initial productivity of gas wells have a significant impact on the overall effectiveness of gas wells.Therefore,it is crucial to further explore rational well patterns and spacing,as well as optimize initial drainage and production technical strategies in order to improve their performance.

Probing the influence of secondary fracture connectivity on fracturing fluid flowback efficiency

A deep understanding of the geometric impacts of fracture on fracturing fluid flowback efficiency is essential for unconventional oil development. Using nuclear magnetic resonance and 2.5-dimensional matrix-fracture visualization microfluidic models, qualitative and quantitative descriptions of the influences of connectivity between primary fracture and secondary fracture on flowback were given from core scale to pore network scale. The flow patterns of oil-gel breaking fluid two-phase flow during flowback under different fracture connectivity were analyzed. We found some counterintuitive results that non-connected secondary fracture (NCSF, not connect with artificial primary fracture and embedded in the matrix) is detrimental to flowbackefficiency. The NCSF accelerates the formation of oil channeling during flowback, resulting in a large amount of fracturing fluid trapped in the matrix, which is not beneficial for flowback. Whereas the connected secondary fracture (CSF, connected with the artificial primary fracture) is conducive to flowback. The walls of CSF become part of primary fracture, which expands the drainage area with low resistance, and delays the formation of the oil flow channel. Thus, CSF increases the high-speed flowback stage duration, thereby enhancing the flowback efficiency. The fracturing fluid flowback efficiency investigated here follows the sequence of the connected secondary fracture model (72%) > the matrix model (66%) > the non-connected secondary fracture model (38%). Our results contribute to hydraulic fracturing design and the prediction of flowback efficiency.

Integrated modeling of fracturing-flowback-production dynamics and calibration on field data:Optimum well startup scenarios

We aim at the development of a general modelling workflow for design and optimization of the well flowback and startup operation on hydraulically fractured wells.Fracture flowback model developed earlier by the authors is extended to take into account several new fluid mechanics factors accompanying flowback,namely,viscoplastic rheology of unbroken cross-linked gel and coupled“fracture-reservoir”numerical submodel for influx from rock formation.We also developed models and implemented new geomechanical factors,namely,(i)fracture closure in gaps between proppant pillars and in proppant-free cavity in the vicinity of the well taking into account formation creep;(ii)propagation of plastic deformations due to tensile rock failure from the fracture face into the fluid-saturated reservoir.We carried out parametric calculations to study the dynamics of fracture conductivity during flowback and its effect on well production for the set of parameters typical of oil wells in Achimov formation of Western Siberia,Russia.The first set of calculations is carried out using the flowback model in the reservoir linear flow regime.It is obtained that the typical length of hydraulic fracture zone,in which tensile rock failure at the fracture walls occurs,is insignificant.In the range of rock permeability in between 0.01 mD and 1 D,we studied the effect of non-dimensional governing parameters as well as bottomhole pressure drop dynamics on oil production.We obtained a map of pressure drop regimes(fast,moderate or slow)leading to maximum cumulative oil production.The second set of parametric calculations is carried out using integrated well production modelling workflow,in which the flowback model acts as a missing link in between hydraulic fracturing and reservoir commercial simulators.We evaluated quantitatively effects of initial fracture aperture,proppant diameter,yield stress of fracturing fluid,pressure drop rate and proppant material type(ceramic and sand)on long-term well production beyond formation linear regime.The third set of parametric calculations is carried out using the flowback model history-matched to field data related to production of four multistage hydraulically fractured oil wells in Achimov formation of Western Siberia,Russia.On the basis of the matched model we evaluated geomechanics effects on fracture conductivity degradation.We also performed sensitivity analysis in the framework of the history-matched model to study the impact of geomechanics and fluid rheology parameters on flowback efficiency.

Investigation of influence factors on CO_(2) flowback characteristics and optimization of flowback parameters during CO_(2) dry fracturing in tight gas reservoirs

CO_(2) dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs,especially in water-scarce areas such as the Loess Plateau.The CO_(2) flowback efficiency is a critical factor that affects the final gas production effect.However,there have been few studies focusing on the flowback characteristics after CO_(2) dry fracturing.In this study,an extensive core-to-field scale study was conducted to investigate CO_(2) flowback characteristics and CH_(4) production behavior.Firstly,to investigate the impact of core properties and production conditions on CO_(2) flowback,a series of laboratory experiments at the core scale were conducted.Then,the key factors affecting the flowback were analyzed using the grey correlation method based on field data.Finally,taking the construction parameters of Well S60 as an example,a dual-permeability model was used to characterize the different seepage fields in the matrix and fracture for tight gas reservoirs.The production parameters after CO_(2) dry fracturing were then optimized.Experimental results demonstrate that CO_(2) dry fracturing is more effective than slickwater fracturing,with a 9.2%increase in CH_(4) recovery.The increase in core permeability plays a positive role in improving CH_(4) production and CO_(2) flowback.The soaking process is mainly affected by CO_(2) diffusion,and the soaking time should be controlled within 12 h.Increasing the flowback pressure gradient results in a significant increase in both CH_(4) recovery and CO_(2) flowback efficiency.While,an increase in CO_(2) injection is not conducive to CH_(4) production and CO_(2) flowback.Based on the experimental and field data,the important factors affecting flowback and production were comprehensively and effectively discussed.The results show that permeability is the most important factor,followed by porosity and effective thickness.Considering flowback efficiency and the influence of proppant reflux,the injection volume should be the minimum volume that meets the requirements for generating fractures.The soaking time should be short which is 1 day in this study,and the optimal bottom hole flowback pressure should be set at 10 MPa.This study aims to improve the understanding of CO_(2) dry fracturing in tight gas reservoirs and provide valuable insights for optimizing the process parameters.

Temporal variations in geochemistry of hydraulic fracturing fluid and flowback water in a tight oil reservoir

Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs.In this study,the injected hydraulic fracturing fluid(HFF)and flowback and produced water(FPW)in tight oil reservoirs of the Lucaogou Formation in the Junggar Basin are temporally sampled from day 1 to day 64.Freshwater is used for fracturing,and HFF is obtained.The chemical and isotopic parameters(including the water type,total salinity,total dissolved solids(TDS),pH,concentrations of Na^(+),Cl^(-),Ba^(+),K^(+),Fe^(2+)+Fe^(3+),and CO_(3)^(2-),dD,and δ^(18)O)are experimentally obtained,and their variations with time are systematically analyzed based on the flowback water.The results show that the water type,Na/Cl ratio,total salinity,and TDS of the FPW change periodically primarily due to the HFF mixing with formation water,thus causing δD and δ^(18)O to deviate from the meteoric water line of Xinjiang.Because of watererock interaction(WRI),the concentrations of Fe^(2+)+Fe^(3+)and CO_(3)^(2-)of the FPW increase over time,with the solution pH becoming more alkaline.Furthermore,based on the significant changes observed in the geochemistry of the FPW,three separate time intervals of flowback time are identified:Stage Ⅰ(<10 days),where the FPW is dominated by the HFF and the changes in ions and isotopes are mainly caused by the WRI;Stage Ⅱ(10-37 days),where the FPW is dominated by the addition of formation water to the HFF and the WRI is weakened;and finally,Stage Ⅲ(>37 days),where the FPW is dominated by the chemistry of the formation water.The methodology implemented in this study can provide critical support for the source identification of formation water.

页岩油蓄能体积压裂开发效果预测与评价方法

蓄能体积压裂(以下简称蓄压)是页岩油藏提前补充地层能量、大幅提升单井产量的主要开发方式,应用广泛。通过渗吸与驱替机理结合实际生产数据统计分析,提出了根据返排率预测蓄压开发阶段最大累计产油量方法。研究结果表明:返排率30%之后,蓄压的累计产油量与返排率对数呈强线性相关,可预测压后单井最大累计产油量;该方法已经得到其他页岩油藏实际生产数据的实证,较递减曲线分析法更加准确且更具普适性,是对储层条件、压裂规模与工艺、焖排采工作制度等主客观因素的综合评价。返排率法可进一步确定液油比和合理返排速度。蓄压排采的平均返排速度控制在6~8 m^(3)(/d·km),与渗吸排油速度相匹配,能够更加高效地利用蓄压补充的弹性能量,取得较高采收率和较低的液油比。单井压后最大可采油量的返排率预测法为蓄压的经济效益评价、生产制度优化、压裂成本控制等提供了依据,对地质-工程一体化、优化井网井距和压裂设计具有重要指导意义。

非常规致密油储层压裂增能一体化技术分析

针对试验区非常规致密油储层常规缝网压裂改造体积有限,压后递减快、稳产差,采出程度低的问题,采用压裂增能一体化工艺,从平衡压力、提高缝控体积及保持能量入手,总结出“补、压、闷、控”的技术思路,通过前置补充能量、增大裂缝与储层接触面积、闷井扩散压力、控制返排等方式,达到压裂增能一体化的目的。现场实施效果表明,采用多级暂堵技术改造体积提高1倍以上,闷井扩散25~30d,无效返排率降低近15个百分点,达到了入井液保持地层能量的目的。与以往单井缝网压裂、整体缝网压裂相比,增油强度分别提高0.27t/(d·m)、0.34t/(d·m);压后前3个月平均单井日增油3.0t,是同期甜点压裂和整体压裂的1.2倍和1.8倍,提产效果显著。结合现场实施及效果分析,优化完善参数设计,形成压裂增能一体化设计原则。

不同水力停留时间对新疆油田压裂返排液COD去除及微生物菌群特征研究

针对新疆油田压裂返排液较难处理的现状,采用生物膜法作为处理工艺的主要单元,探究不同水力停留时间(HRT)对化学需氧量(COD)去除的影响,通过高通量测序和功能预测确定不同水力停留时间下的微生物群落特征.结果表明:水力停留时间48 h是生物膜法处理新疆油田压裂返排液的适宜水力停留时间,COD去除效率最高,进水COD平均去除率46.77%,平均去除速率83.33 mg·(L·d)^(-1).相对于水力停留时间36、72 h,水力停留时间48 h的微生物多样性更高,群落组成更丰富,且形成以Proteobacteria(变形菌门)、Firmicutes(厚壁菌门)、Campylobacterota(弯曲菌门)、Bacteroidota(拟杆菌门)和Desulfobacterota(脱硫菌门)为主要优势菌的微生物群落.微生物菌群具有难降解物质代谢的功能基因,可促进新疆油田压裂返排液的生物降解.

页岩气储层压裂返排一体化裂缝导流能力变化规律

为研究页岩气储层压裂返排一体化过程中裂缝导流能力的变化规律,结合页岩气储层生产特点,模拟了整个压裂—返排—生产的过程,开展气测—液测—气测3个连续阶段裂缝导流能力测试实验,研究了整个过程中裂缝导流能力的变化规律。结果表明:在闭合压力为35 MPa的条件下,采用蒸馏水模拟压裂后,由于页岩水化的作用,石英砂支撑剂的导流能力降低幅度高达80.4%;在模拟返排过程中,按初始气测排量的25%、50%、75%、100%进行气测导流能力实验,裂缝导流能力逐渐升高,实验方案中其最大恢复值为初始值的65.9%;实验模拟了生产过程中由于页岩气井产量变化造成的地层压力波动对裂缝导流能力的影响。研究结果对页岩气储层压裂方案设计优化和高效开发具有一定的参考意义。

过一硫酸盐/高铁酸盐体系处理页岩气压裂返排液实验研究

针对高盐难降解的页岩气压裂返排液,探究过一硫酸盐(PMS)/高铁酸盐(Fe(VI))体系氧化其中有机物的可行性。对比了活化PMS的不同方式及不同氧化工艺;设计了L_(16)(4~4)正交实验优化氧化反应参数;考察了该体系在氧化的同时达到的混凝和软化效果。结果表明,PMS/Fe(VI)体系在最佳反应条件下(即PMS的浓度为1 800 mg/L,Fe(VI)浓度为1 200 mg/L,pH为5,反应温度为35℃时)TOC的去除率为46.4%,其中各因素的贡献值分别是19.34%、51.31%、15.38%、13.68%。在高效矿化有机物的同时能去除返排液中99.5%的总悬浮固体(TSS)和95.2%的Ba^(2+)。研究结果可为页岩气压裂返排液预处理工艺单元的设计和运行提供参考。

页岩储层压后油水排采动态解释模型及矿场应用

页岩油藏大规模体积压裂后,返排与早期生产通常表现出显著的油水同产特征,定量分析油水排采动态成为解释压裂缝及储层参数的一种新手段,但目前油水排采动态解释模型及应用还较欠缺。基于页岩储层压裂后压裂液赋存假设,首先建立考虑压裂缝存在条件下的水相和油相流动方程,然后通过拟时间和拟压力变量将方程线性化,推导水相和油相动态解释模型的解析解和特征解,最终形成油相图版拟合和水相直线分析联合的排采动态解释方法。研究结果表明:在双对数诊断曲线中,油相流动表现为斜率为1/2的改造区线性流和斜率为1的改造区边界控制流,水相流动表现为斜率为1/2的压裂缝线性流和斜率为1的压裂缝边界控制流。所建立的油水排采动态解释模型可较好地解释压裂缝及储层参数。基于中国西部某页岩区块的油藏、压裂及动态资料,反演了矿场压裂井的压裂缝半长、导流能力与改造区渗透率、宽度,其中压裂缝半长为50~130 m,导流能力为20~80 mD·m;改造区渗透率为0.01~0.05 mD,宽度为24~27 m。依据反演的压裂缝及改造区参数,建立压裂水平井排采数值模拟模型,基于解释结果的模拟产量与实际值吻合程度高,且后期产量预测值合理。所建立的油水排采动态解释模型完善了页岩油藏动态分析方法,对页岩油藏排采特征定量分析、压裂效果评价及高效开发对策制定提供了依据。

页岩气返排水中的反硝化厌氧甲烷氧化微生物——群落结构与关键影响因子

首次探究了高温高压高盐的页岩气返排水中DAMO(denitrifying anaerobic methane oxidation)微生物存在的证据及其与关键环境因子之间的关联性.结果表明,在所研究的7个页岩气井场返排水中均检测到了DAMO古菌与细菌的存在,且古菌的丰度远高于细菌,其16S rRNA基因拷贝数分别为4.32×10^(4)~5.83×10^(5)copies/L和1.16×10^(3)~6.00×10^(3)copies/L.DAMO古菌与细菌的功能基因mcrA与pomA同样在所有的样品中检出.页岩气返排水中共发现了4个DAMO细菌代表性OTU与1个DAMO古菌代表性OTU,虽然返排水中盐度很高,但检出的DAMO细菌与古菌与已报道的淡水环境中的DAMO微生物亲缘性更近.RDA相关性分析表明,返排水常规理化因子对DAMO微生物的影响并非体现在微生物的丰度上,而是体现在微生物的功能上,其中pmoA基因丰度与TOC含量呈正显著相关,而mcrA基因丰度则与NO_(3)^(-)、NH_(4)^(+)、PO_(4)^(3-)和Cl^(-)浓度呈正相关,Cl^(-)影响最大.研究结果拓展了关于DAMO微生物环境分布的认识,可为缓解返排水中逸散甲烷所导致的温室效应的控制提供理论基础,也有助于加深对深部页岩微生物过程的认知.

页岩油储层CO 2前置蓄能对压裂液返排效率影响规律

CO 2前置蓄能压裂具有增能效果好、返排速度快、储层伤害小等优势,是一种极具前景的储层改造措施。利用数值模拟方法考察了储层参数(毛细管压力、基质渗透率)和工程参数(焖井压力、焖井时间、返排速度和返排压力)对页岩油储层CO 2前置蓄能压裂返排效果的影响规律,分析了各参数对压裂液返排效率的影响机制。结果表明,储层渗透率和毛管力越低,压裂液返排阻力越大,返排率越低;渗透率对CO 2蓄能效果的影响更为显著,毛管力对压裂液返排速度的影响很小。工程因素主要通过对CO 2的有效蓄能和液体压裂液因渗吸、滤失等原因滞留来影响返排效果。优化的返排参数范围内,压裂液返排率提升超过5%,原油采收率提升超过7%。在该制度下CO 2前置蓄能不仅可以为储层提供充足的返排和生产动力,还可以提高孔隙动用范围,提高原油采收率。

返排液重配压裂液性能研究及现场应用

随着非常规油气资源大规模开发,产生大量的压裂返排液,将压裂后的返排液进行重复利用,不仅能保护环境,还可以节约水资源,降低成本。本文针对鄂尔多斯盆地某区块设计一套压裂返排液初级处理工艺,研究处理后的压裂返排液重配进行施工,室内研究表明,该W-1压裂液各项性能良好:在170 s^(-1)、60℃,剪切120 min,黏度为224.500 mPa·s;50℃下破胶2 h,破胶液黏度在1.460 mPa·s;表面张力为21.791 mN/m、界面张力为0.769 mN/m;防膨率85.10%;在60℃下,压裂液冻胶体系静态悬砂时间为60 min,表明了该压裂液有较好的携砂性能;岩心基质渗透率伤害率为14.12%。该井现场施工情况表明,压裂液性能良好,施工压力稳定。压后1 h快速放喷返排,返排效果良好,压后增产效果显著。

胍胶压裂返排液COD的电化学降解实验研究

为研究电化学法对胍胶压裂返排液中化学需氧量(COD)的去除效果,本实验采用Al和Fe极板作为电极材料。通过响应面法分析了反应过程,并考察了反应动力学模型。实验结果显示,Al极板在2.5 cm间距、135 mA/cm^(2)电流密度下,经过120 min处理,可实现85.29%的COD去除率。响应面模型系数具有显著的相关性,且模型的精确度和可信度均符合要求。去除COD的过程符合一级动力学模型。对于Fe极板,同样的极板间距和电流密度条件下,90 min处理后,取上清液进行60 min的二次电化学反应,并在每30 min加入40 mL H_(2)O_(2)。最终,COD去除率提升至97.65%,浓度降至80 mg/L,满足国家污水综合排放标准(<100 mg/L)。

化学氧化-絮凝工艺在压裂返排液除硼中的应用

为降低压裂返排液中的硼含量,满足水样回用配液或外排标准,以5口水平井压裂后的返排液为研究对象,考察了氧化剂类型、投加量、预处理条件、沉淀剂类型、投加量对化学氧化工艺的影响;在化学氧化工艺出水的基础上,考察了絮凝剂投加量、搅拌速度和加药时间间隔对絮凝工艺的影响,并监测了两者耦合联用后的效果。结果表明,H_(2)O_(2)和BaCl_(2)分别作为氧化剂和沉淀剂时,除硼效果较好,建立了最佳投加量与返排液中初始硼浓度相关的线性方程,便于现场快速选定加药浓度;当PAC浓度为80 mg/L、PAM浓度为5 mg/L、搅拌速度30 r/min、加药时间间隔30 s时,絮凝工艺的处理效果最优;将化学氧化-絮凝工艺耦合后,在氧化反应pH值为9、氧化反应时间为30 min,沉淀反应pH值为9和最佳絮凝工艺的条件下,可保证滤液中硼质量浓度小于5 mg/L,满足回用配液的要求。研究结果可为压裂返排液的高效、清洁处理提供实际参考。

页岩气中甲烷在返排液中溶解度的研究进展

天然气在清洁能源市场中占据越来越重要的地位,在“碳达峰”与“碳中和”的战略背景下,非常规天然气—页岩气开采行业正面临甲烷逸散治理的严峻挑战。压裂、生产过程中甲烷大量无规则的逸散不仅浪费资源,更对周边环境乃至全球生态系统都构成了巨大的威胁。如何精确了解甲烷排放速率,是构建页岩气排放评估体系把控手段中重要的一环。甲烷溶解度的变化直接影响甲烷的逸散速率与总量,因此,对其规律的探索成为当前研究的重中之重。本文在前人实验的基础上,对影响甲烷溶解度的温度、压力以及矿化度等因素进行了深入论述,有助于构建排放评估体系、优化工艺设计,为实现减排目标提供理论支持。