Characterization and prevention of formation damage for fractured carbonate reservoir formations with low permeability

Stress sensitivity and water blocking in fractured carbonate reservoir formations with low permeability were determined as the main potential damage mechanisms during drilling and completion operations in the ancient buried hill Ordovician reservoirs in the Tarim Basin. Geological structure, lithology, porosity, permeability and mineral components all affect the potential for formation damage. The experimental results showed that the permeability loss was 83.8%-98.6% caused by stress sensitivity, and was 27.9%-48.1% caused by water blocking. Based on the experimental results, several main conclusions concerning stress sensitivity can be drawn as follows： the lower the core permeability and the smaller the core fracture width, the higher the stress sensitivity. Also, stress sensitivity results in lag effect for both permeability recovery and fracture closure. Aimed at the mechanisms of formation damage, a modified low-damage mixed metal hydroxide （MMH） drilling fluid system was developed, which was mainly composed of low-fluorescence shale control agent, filtration control agent, lowfluorescence lubricant and surfactant. The results of experimental evaluation and field test showed that the newly-developed drilling fluid and engineering techniques provided could dramatically increase the return permeability （over 85%） of core samples. This drilling fluid had such advantages as good rheological and lubricating properties, high temperature stability, and low filtration rate （API filtration less than 5 ml after aging at 120 ℃ for 4 hours）. Therefore, fractured carbonate formations with low permeability could be protected effectively when drilling with the newly-developed drilling fluid. Meanwhile, field test showed that both penetration rate and bore stability were improved and the soaking time of the drilling fluid with formation was sharply shortened, indicating that the modified MMH drilling fluid could meet the requirements of drilling engineering and geology.

Genesis of the low-permeability reservoir bed of upper Triassic Xujiahe Formation in Xinchang gas field,western Sichuan Depression

The genesis of a reservoir is a result of the combined action of deposition, diagenesis, tectonic reworking, and interaction of rock and fluid and the evolutionary environment. We discuss the genetic and evolution mechanism of a low-permeability reservoir bed of the Xujiahe Formation in the western Sichuan Depression on the basis of the study of diagenesis, diagenetic reservoir facies and the diagenetic evolution sequence. The research indicated that this reservoir bed can be divided into five types of diagenetic reservoir facies, namely strong dissolution, chlorite-lined intergranular pores, compaction and pressure solution, carbonate cementation and secondary quartz increase. There are, however, just two diagenetic reservoir facies which provide low-permeability reservoir beds, namely strong dissolution and chlorite-lined intergranular pores. We also analyzed their diagenetic evolution sequences and the origin of the low-permeability reservoir bed. Besides, it was also indicated that the composition and structure of sandstones, types of sedimentary microfacies, diagenesis history as well as the tectonic reworking in later periods are the main factors controlling the formation of the low-permeability reservoir bed. The above- mentioned factors establish the foundation for the forecasting the distribution of high quality reservoir beds.

Diagenesis-porosity evolution and“sweet spot”distribution of low permeability reservoirs:A case study from Oligocene Zhuhai Formation in Wenchang A sag,Pear River Mouth Basin,northern South China Sea

The characteristics of low permeability reservoirs and distribution of sweet spots in the Oligocene Zhuhai Formation of Wenchang A sag, Pearl River Basin were investigated by core observation and thin section analysis. The study results show that there develop the fine, medium and coarse sandstone reservoirs of tidal flat–fan delta facies, which are of mostly low permeability and locally medium permeability. There are two kinds of pore evolution patterns: oil charging first and densification later, the reservoirs featuring this pattern are mainly in the third member of Zhuhai Formation between the south fault zone and the sixth fault zone, and the pattern of densification first and gas charging later is widespread across the study area. Strong compaction and local calcium cementation are the key factors causing low permeability of the reservoirs in the Zhuhai Formation. Thick and coarse grain sand sedimentary body is the precondition to form "sweet spot" reservoirs. Weak compaction and cementation, dissolution, early hydrocarbon filling and authigenic chlorite coating are the main factors controlling formation of "sweet spot" reservoir. It is predicted that there develop between the south fault and sixth fault zones the Class Ⅰ "sweet spot" in medium compaction zone, Class Ⅱ "sweet spot" in nearly strong compaction zone, Class Ⅲ "sweet spot" reservoir in the nearly strong to strong compaction zone with oil charging at early stage, and Class IV "sweet spot" reservoir in the strong compaction and authigenic chlorite coating protection zone in the sixth fault zone.

The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs:a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie

The relationships between permeability and dynamics in hydrocarbon accumulation determine oil- bearing potential （the potential oil charge） of low perme- ability reservoirs. The evolution of porosity and permeability of low permeability turbidite reservoirs of the middle part of the third member of the Shahejie Formation in the Dongying Sag has been investigated by detailed core descriptions, thin section analyses, fluid inclusion analyses, carbon and oxygen isotope analyses, mercury injection, porosity and permeability testing, and basin modeling. The cutoff values for the permeability of the reservoirs in the accumulation period were calculated after detailing the accumulation dynamics and reservoir pore structures, then the distribution pattern of the oil-bearing potential of reservoirs controlled by the matching relationship between dynamics and permeability during the accumulation period were summarized. On the basis of the observed diagenetic features and with regard to the paragenetic sequences, the reservoirs can be subdivided into four types of diagenetic facies. The reservoirs experienced two periods of hydro- carbon accumulation. In the early accumulation period, the reservoirs except for diagenetic facies A had middle to high permeability ranging from 10 × 10-3 gm2 to 4207 × 10-3 lain2. In the later accumulation period, the reservoirs except for diagenetic facies C had low permeability ranging from 0.015 × 10-3 gm2 to 62× 10-3 -3m2. In the early accumulation period, the fluid pressure increased by the hydrocarbon generation was 1.4-11.3 MPa with an average value of 5.1 MPa, and a surplus pressure of 1.8-12.6 MPa with an average value of 6.3 MPa. In the later accumulation period, the fluid pressure increased by the hydrocarbon generation process was 0.7-12.7 MPa with an average value of 5.36 MPa and a surplus pressure of 1.3-16.2 MPa with an average value of 6.5 MPa. Even though different types of reservoirs exist, all can form hydrocarbon accumulations in the early accumulation per- iod. Such types of reservoirs can form hydrocarbon accumulation with high accumulation dynamics; however, reservoirs with diagenetic facies A and diagenetic facies B do not develop accumulation conditions with low accumu- lation dynamics in the late accumulation period for very low permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock, Also at these depths, lenticular sand bodies can accumulate hydrocarbons. At shallower depths, only the reservoirs with oil-source fault development can accumulate hydrocarbons. For flat surfaces, hydrocarbons have always been accumulated in the reservoirs around the oil-source faults and areas near the center of subsags with high accumulation dynamics.

A quantitative evaluation for well pattern adaptability in ultra-low permeability oil reservoirs:A case study of Triassic Chang 6 and Chang 8 reservoirs in Ordos Basin

Based on the previous studies and development practice in recent 10 years, a quantitative evaluation method for the adaptability of well patterns to ultra-low permeability reservoirs was established using cluster analysis and gray correlation method, and it includes 10 evaluation parameters in the four aspects of optimal evaluation parameters, determination of weights for evaluation parameters, development stage division, and determination of classification coefficients. This evaluation method was used to evaluate the well pattern adaptability of 13 main ultra-low permeability reservoirs in Triassic Chang 6 and Chang 8 of Ordos Basin. Three basic understandings were obtained: Firstly, the well pattern for ultra-low permeability type-I reservoirs has generally good adaptability, with proper well pattern forms and well pattern parameters. Secondly, square inverted nine-spot well pattern is suitable for reservoirs with no fractures; rhombic inverted nine-spot injection pattern is suitable for reservoirs with some fractures; and rectangular well pattern is suitable for reservoirs with rich fractures. Thirdly, for the ultra-low permeability type-Ⅱ and type-Ⅲ reservoirs, with the principles of well pattern form determination, the row spacing needs to be optimized further to improve the level of development of such reservoirs.

碎软低渗煤储层强化与煤层气地面开发技术进展

我国碎软低渗煤储层分布广泛,然而由于其煤体松软、破碎、渗透性差,常规的直井/水平井煤储层直接压裂技术应用于碎软低渗煤储层强化及其煤层气地面开发的效果并不理想,碎软低渗煤储层煤层气的高效开发是制约我国煤层气产业大规模发展以及煤矿瓦斯高效治理的重要技术瓶颈。在系统分析我国碎软低渗煤储层特征及煤层气地面开发中存在的问题基础上,以水平井为基础井型,围绕间接压裂、应力释放和先固结后压裂3种不同的技术方向,梳理了目前碎软低渗煤储层强化与煤层气地面开发技术进展。归纳评述了以顶板间接压裂、夹矸层间接压裂以及硬煤分层间接压裂为内涵的间接压裂煤层气开发技术,以水力喷射造穴、气体动力造穴、扩孔+水力喷射+流体加卸载诱导失稳造穴、水力割缝为不同应力释放方式的应力释放煤层气开发技术,以及先微生物诱导碳酸钙固结碎软煤储层再进行水力压裂的先固结后压裂煤层气开发技术。间接压裂技术的工程实践探索已有较多积累,在地质条件适宜地区对碎软低渗煤储层强化取得了较好效果,而以应力释放为代表的碎软低渗煤储层强化新技术探索已取得重大进展,并进入工程试验和验证阶段。水平井应力释放技术针对碎软低渗煤储层特性和新的开发原理,其对储层改造潜力更大、煤层气开发效果会更好。基于水平井应力释放技术,围绕扩大应力释放范围、提高煤层气开发效果以及实现煤与煤层气共采3个方面,对碎软低渗煤储层强化及煤层气地面开发技术的发展趋势进行了展望,以期为改善我国碎软低渗煤储层增产改造效果以及提高煤层气单井产量提供参考。

准噶尔盆地环东道海子凹陷侏罗系煤层气成藏条件及勘探方向

为了明确准噶尔盆地环东道海子凹陷侏罗系煤层气勘探方向,开展了煤层连井对比、井-震标定和地震资料解释以及煤层测、录井资料分析。研究结果表明:①准噶尔盆地侏罗系西山窑组和八道湾组煤层发育,厚度较大,分布稳定,其中西山窑组发育2~3层煤层,累计最大厚度为20 m,八道湾组发育2~4层煤层,累计最大厚度为29 m。煤岩含气性好,录井气测异常明显。②环东道海子凹陷内中下侏罗统煤系烃源岩为中等—好烃源岩,Ro为0.6%~0.8%,处于低成熟—成熟阶段,具有较好的生气能力;天然气碳同位素分析结果显示,煤层气亦可来源于深部高成熟腐殖型有机质。③研究区西山窑组煤岩为中—低孔、低渗储层,孔隙度为7.0%~20.8%,渗透率为0.32~8.67 mD;八道湾组煤岩为低孔、中—低渗储层,孔隙度为5.6%~7.8%,渗透率为2.30~13.83 mD;煤层夹于泥岩之间且煤层之上区域性泥岩盖层分布广泛,封盖保存条件好。④研究区存在凹陷区源内煤层气富集成藏和凸起区深部外源气富集成藏等2种模式。环东道海子凹陷煤层气勘探潜力较大,特别是凹陷北东方向斜坡区和凹陷北部斜坡—滴南凸起区。

长岭断陷龙凤山气田营城组储层非均质性研究

龙凤山气田是目前中石化在东北地区勘探开发的首个深盆致密砂岩近饱和高含油凝析气储集系统,主力含气层位营城组储层在空间上表现出了较强的非均质性特征,气层在纵向上、平面上分布规律复杂将制约后续的地质研究工作(于翠玲,2007)。通过对岩心描述和测井资料进行分析,对比地质储量和实际测试生产情况,从层内、层间和平面3个方面分析储层的宏观非均质性。

鄂尔多斯盆地西部古峰庄地区三叠系延长组裂缝特征及其对低渗透油藏的控制作用

[研究目的]鄂尔多斯盆地西部古峰庄地区三叠系延长组属于低渗透储层,天然裂缝较为发育,以往对裂缝特征研究较少,开展天然裂缝特征和形成时期研究对低渗透油藏勘探开发具有重要作用。[研究方法]文章通过野外露头、钻井岩心、成像测井、扫描电镜裂缝识别和流体包裹体、断裂活动、构造应力分析等方法展开了古峰庄地区延长组天然裂缝特征和控藏作用研究。[研究结果]延长组各段天然裂缝均发育,以长7段最为发育,其次为长8、长6段;裂缝以高角度裂缝和垂直裂缝为主,走向以NEE向为主,NE向次之,少量NW和NWW向;裂缝面可见方解石充填和明显过油痕迹。天然裂缝发育程度与岩层厚度、断裂活动密切相关。裂缝形成时期具有多期性,主要为燕山期和喜马拉雅期。[结论]延长组天然裂缝的发育改善了研究区低渗透储层的孔渗能力和储集空间,为低渗透油藏运移、储集和富集提供了良好条件,其发育程度与形成时期影响着低渗透油藏的成藏和产能。

海上油田低渗储层岩石扩容低效原因及储层改造工艺

针对岩石扩容技术在低渗储层作业时间长、易损坏井下工具及应用低效等问题,提出将岩石力学领域的碎胀扩容机理用于石油工程储层改造的新思路。开展了岩石扩容工艺数值模拟敏感性及作业井例分析,分析了岩石碎胀微观机理,提出了前置简易水力压裂和岩石扩容、爆燃压裂和岩石扩容联作等实现岩石碎胀扩容工艺路径,并指出了下一步数值模拟、物理模拟、裂缝监测等技术研究方向。结果表明:物性越差扩容效果逐渐变差,是低渗储层岩石扩容低效的主因;岩石碎胀扩容储层改造工艺可利用多种工艺技术组合形成复杂缝网,从而提高现有改造技术实施效果。本文研究成果可对海上低渗储层改造工艺的进一步发展和优选提供参考。

洛河组砂岩用新型无固相冻胶注浆体系

洛河组砂岩采动地层涌水频繁,严重影响了矿井安全生产。针对传统注浆体系面临渗滤效应严重和成胶性能不可控,难以实现裂隙出水有效调控的技术难题,通过分析5种天然典型岩心样品(含砾砂岩、巨粒砂岩、粗粒砂岩、中粒砂岩、细粒砂岩)的矿物组成及微观形貌,明确了孔隙微观赋存特征,构建了低成本、稳定性优异的无固相冻胶注浆体系。通过物理模拟驱替实验研究了冻胶注浆体系的注入性和封堵性能,通过核磁共振在线驱替实验研究了注浆封堵前后岩心中的孔隙分布变化特征。结果表明,孔隙直径小和孔喉连通性差是造成传统注浆体系难以顺利注入和深部运移的地质原因。由于渗滤效应的存在,传统注浆体系的固化封堵效果明显低于理论设计。以0.5%~0.6%聚丙烯酰胺、0.6%~0.7%有机胺类单体交联剂、0.07%~0.08%酚类单体交联剂和0.2%~0.3%有机酸类调节剂为原料,构建了低成本、无固相、易深部注入的新型冻胶注浆体系。该冻胶注浆体系可实现48h内成胶,180d内未见明显脱水,长期老化稳定性优异。冻胶注浆体系的注入性良好,持续冲刷岩心后的压力衰减率为7.85%~20.95%,封堵率为82.04%~92.19%。冻胶注浆体系通过占据大孔道或裂缝空间,增大渗流阻力,迫使后续流体转向,实现出水层有效封堵。该研究成果可为洛河组砂岩注浆堵水施工提供新思路。

“一点法”产能评价方法的内涵、矿场应用及改进

近年来,在四川盆地气井产能评价实践中发现,针对低渗强非均质性和中高渗储层,常规“一点法”适用性差。为探索并解决该问题,文中系统梳理并总结了“一点法”产能评价方法的不同形式,揭示了其内涵。“一点法”的内涵主要包括均质储层、可靠的稳定经验数、气井现场测试达到拟稳定渗流状态3个方面,围绕这3个方面的内涵,指明了“一点法”的矿场应用偏差。在此基础上,首先深入剖析了“一点法”计算参数的敏感性;其次对矿场应用提出了改进和数据处理方法,建立了稳定经验数与试井地层系数的经验关系式及不同层系试井地层系数与测井储能系数拟合关系式;再次,提出了不同类型气井测试数据评价方法及试油建议;最后应用文中建立的“一点法”改进方法对四川盆地不同气田的31口气井进行了计算对比,验证了方法的可靠性和可行性。该改进方法不仅适用于常规“一点法”的应用领域,也适用于具有低渗强非均质性、中高渗地质特征的气田,弥补了特定地质条件下常规“一点法”确定气井稳定产能误差大的不足,对于气田的开发设计、规模调整和现场生产组织均具有积极意义。

二连盆地阿南凹陷白垩系凝灰岩类储层特征及有利区分布

阿南凹陷白垩系腾一下亚段凝灰岩类储层是近年来二连盆地致密油勘探的重点领域。通过岩心观察、薄片鉴定、储层物性分析及X-衍射分析等,采用高压压汞、氮气吸附、场发射电镜、CT扫描等实验方法,分析了二连盆地阿南凹陷白垩系凝灰岩类储层的岩性、物性、储集空间类型和孔隙结构特征,结合有利储层形成机制预测了有利储层发育区。研究结果表明:①二连盆地阿南凹陷白垩系腾一下亚段发育凝灰岩、沉凝灰岩、凝灰质泥岩、凝灰质(粉)砂岩4种凝灰岩类。②研究区凝灰岩类储层物性变化范围较大,平均孔隙度为4.88%,其中超低孔、特低孔的样品数占比为83.6%,平均渗透率为0.067 mD,整体属于超低孔、超低渗储层。凝灰岩主要发育溶蚀孔和脱玻化孔,呈“立体”网络孔隙结构,以介孔、宏孔为主,储层物性最好;凝灰质(粉)砂岩主要发育溶蚀孔和粒间孔,具有微细孔—微喉孔隙结构,介孔发育,储层物性较好;沉凝灰岩和凝灰质泥岩主要发育溶蚀孔、晶间孔和微裂缝,多发育孤立型孔隙结构,以介孔为主,储层物性较差。③研究区凝灰岩类优质储层受沉积作用、成岩作用和构造作用共同控制,沉积作用为优质储层形成提供了物质基础,控制了储层的形成和分布;压实作用和胶结作用降低了储层物性,白云岩化和脱玻化作用改善了储集性能;溶蚀作用是有效储层形成的关键,对物性改善具有积极作用。④研究区发育Ⅰ,Ⅱ,Ⅲ类凝灰岩类储层,Ⅰ类储层集中分布在洼槽区,Ⅱ类储层沿西部缓坡呈条带状分布,Ⅲ类储层分布范围最广。其中A43东、A27北、H16西和A11西南等区块发育的Ⅰ类储层是下一步凝灰岩类致密油勘探的有利区带。

高压低渗透碎屑岩储层孔隙结构特征及分类评价——以莺歌海盆地东方A 1区黄流组一段为例

为揭示低渗储层的微观孔喉差异,根据岩心、测井、测试和岩心实验分析等资料,采用分形理论和多层感知器神经网络方法,分析储层孔隙结构特征,进行储层量化表征。结果表明:储层岩性以细砂岩和粉砂岩为主,受超压保护及沉积—成岩作用影响,主水道储层粒度相对较粗,原生粒间孔占比可达60%;泥质质量分数越高,粒间孔越不发育;压力因数越高,粒间孔越发育,压力因数每提高0.1,储层中粒间孔隙占比增加5%~10%。低渗储层分4种类型:Ⅰ类储层,表现为中孔、低渗特征,压汞曲线具有明显的平台段,孔喉或核磁曲线为单峰分布特征,T 2弛豫时间的主峰分布在40 ms附近,可动流体饱和度平均为53.2%;Ⅱ类储层,表现为中孔、低渗特征,孔隙度与Ⅰ类储层的相当,渗透率明显降低,压汞曲线表现一定的平台段,但进汞曲线末段斜率明显增大,孔喉或核磁曲线呈双峰分布特征,右峰T 2弛豫时间在60 ms附近,左峰的在10 ms附近;Ⅲ类和Ⅳ类储层,分别表现为中孔、特低渗和低孔、特低渗特征,压汞曲线无明显平台段,大孔喉与Ⅰ、Ⅱ类储层相比,孔喉形态更加复杂,孔喉和核磁曲线呈单峰分布,孔喉半径和T 2弛豫时间峰值逐渐向左偏移,可动流体饱和度小于20%。优选密度、中子、电阻和自然伽马参数建立基于MLP的储层类型测井识别方法,储层识别正确率达86.7%,与岩心实验分析吻合率达88.9%,产能匹配性较好。该结果可为研究区低渗气藏的有效开发提供依据。

低渗透率油藏二流量试井影响因素

为解决低渗透率油藏二流量试井测试成功率低、解释误差大的问题,从低渗透率油藏二流量试井技术的测试原理和解释原理出发,结合低渗透率油藏的地质特征、生产特征,围绕现场测试、井底压力折算、地层参数计算进行重点分析;剖析低渗透率油藏二流量试井现场测试、井底压力折算、地层参数计算过程中存在的主要问题及影响因素,针对各环节存在的问题针对性地提出改进措施并在现场进行应用。现场应用结果证明改进措施能有效提高低渗透率油藏二流量试井的测试成功率和解释符合率,该技术的推广应用有助于为油田生产及措施调整提供数据支撑。

低渗凝灰质砂岩储层孔隙结构特征及低渗成因——以珠江口盆地陆丰凹陷古近系文昌组为例

陆丰凹陷古近系文昌组为典型低渗凝灰质砂岩储层,复杂的孔隙结构和储层低渗特征制约研究区增储上产。利用铸体薄片观察、XRD全岩及黏土矿物分析、高压压汞、恒速压汞和CT扫描等实验,基于分形曲线特征和孔喉结构参数划分储层孔喉类型,分析储层物性及填隙物特征,精细表征砂岩储层的孔喉—孔隙结构,探讨不同类型储层的孔隙结构特征及其对物性的影响。结果表明:珠江口盆地陆丰凹陷古近系文昌组储层发育长石石英砂岩、岩屑石英砂岩和岩屑砂岩。储层孔喉结构划分3种类型,Ⅰ类储层为优质储层,储层物性最优,平均排驱压力约为0.1 MPa;Ⅱ类储层次之,排驱压力在0.5~1.0 MPa之间;Ⅲ类储层最差,排驱压力大于1.0 MPa。研究区储层低孔低渗特征是填隙物类型、溶蚀作用程度和蚀变产物性质等因素共同作用的结果,凝灰质填隙物大量充填原生孔隙空间,受溶蚀作用程度低是研究区储层低孔的主要原因,溶蚀作用产物易堵塞喉道是储层形成低渗特征的主控因素。该结果为研究区低渗储层划分及有效开发提供指导。

珠江口盆地陆丰凹陷文昌组凝灰质砂岩储层成岩相及发育模式

陆丰凹陷文昌组深层砂岩储层是珠江口盆地珠一坳陷最重要的油藏储集岩之一,而凝灰质发育导致储层致密,渗透率呈现低渗、特低渗特征。由于凝灰质影响,该区成岩作用及其展布表现出特殊性。运用偏光显微镜在对凝灰质砂岩储层的成岩作用、自生矿物转化及孔隙类型详细观察的基础上,结合扫描电镜、孔渗测试及测井资料分析,对陆丰凹陷文昌组凝灰质砂岩储层成岩相及其发育模式进行了研究。结果表明,凝灰质蚀变作用是影响储层物性的主要成岩作用,其次是压实作用和溶蚀作用。依据各种成岩作用强度及其组合,储层整体可以分为5种成岩相:①中压实--弱胶结--凝灰质中等溶解相(Ⅰ类);②中强压实--弱胶结--凝灰质强溶解相(Ⅱ类);③中强压实--磷灰石中强胶结--中等溶解相(Ⅲ类);④中强压实--高岭石中强胶结--弱溶解相(Ⅳ类)和⑤强压实--弱胶结--弱溶解相(Ⅴ类)。其中Ⅰ类成岩相为优质成岩相(孔隙度均值为13.4%、渗透率均值为5.4×10^(-3)μm^(2)),Ⅱ类成岩相为有利成岩相(孔隙度均值为15.4%、渗透率均值为1.5×10^(-3)μm^(2)),Ⅲ类和Ⅳ类成岩相为潜在有利成岩相(孔隙度均值为15.0%、渗透率均值为1.0×10^(-3)μm^(2)),Ⅴ类成岩相为不利成岩相。受大气水淋滤和有机酸溶蚀等影响,陆丰凹陷文昌组深层砂岩储层主要发育Ⅱ-Ⅲ-Ⅳ-Ⅴ和Ⅰ-Ⅴ两种成岩相组合模式。成岩相与储层质量密切相关,通过识别优质成岩相可以预测有利储层分布,为油气勘探提供地质依据。

北部湾盆地乌石W油田流沙港组三段低渗储层物性主控因素及有利储层预测

利用铸体薄片、扫描电镜、阴极发光等多种技术手段,对北部湾盆地东北部乌石W油田始新统流沙港组三段厚层砂砾岩低渗储层储集物性的非均质性成因进行了深入研究,并应用测井参数,通过地质建模建立不同井区储层物性预测模型,进而预测了有利含油储层的分布特点。研究表明:①流沙港组三段Ⅱ油组储层总体为中孔低渗,渗透率平面变化趋势与孔隙度变化趋势不同。其中,近物源区储层为中孔特低渗;处于近物源与远物源之间的中部地区为中孔低渗;远物源区则为中低孔中渗。②储层物性受沉积微相和成岩作用的共同控制,主控因素为埋深(压实)、泥质含量、岩性(粒度、岩石成分)、溶蚀和破裂的非均质性等。③相对高孔储层区位于2/3/5井区及7井以南小断块,为有利储集层发育区,而相对高渗储层区则多位于8、9井区,为有利含油气储层之油气开发潜力区。

地层压力取值误差对低渗气藏气井产能方程的影响及矫正方法

气井产能试井有时会因为开发或测试工艺等因素造成二项式产能方程出现较大误差,甚至会有负斜率的异常情况。对于低渗气井,供给范围内的平均地层压力随着生产会有较大幅度下降,如果没有准确的地层压力参考,将无法获得符合实际情况的产能方程和无阻流量。针对低渗储层气井探测范围内平均地层压力的测量或取值误差问题,利用不同制度的产量和井底流压数据,结合二项式压力平方产能方程,利用回归方法确定平均地层压力。通过低渗气井产能测试实例计算,回归分析得到的平均地层压力能够较准确地计算出二项式产能方程和无阻流量,为后续生产井的开发和配产提供有效指导。

基于双峰高斯函数的海上低渗储层孔隙结构定量表征——以琼东南盆地BD21气田陵水组三段为例

海上低渗气藏占比增加,孔隙结构的差异影响气井产能,制约海上低渗气藏规模开发。根据高压压汞和核磁共振实验,采用测井曲线与储层分类参数、双峰高斯函数拟合曲线等方法,利用球状孔隙模型将核磁共振T2谱转化为伪毛细管压力曲线定量表征孔径大小及分布,分析核磁共振T2谱反映的大孔孔隙度、大中孔孔隙度与物性、压汞参数之间关系,分析反映储层渗流能力的孔隙结构评价参数,建立孔隙结构和物性参数预测模型。结果表明:陵水组三段低渗储层孔隙结构分布呈双峰型和单峰型,其中小孔曲线与大孔曲线存在重叠区域,双峰型曲线的重叠区域较小,单峰型曲线的重叠区域较大,孔隙可按双峰高斯函数拟合的小孔曲线、大孔曲线和重叠区域的分布范围划分为大孔、中孔和小孔;大中孔孔隙度、大孔孔隙度可有效评价储层物性和孔隙结构,储层大中孔越发育,物性越好,可动流体饱和度相对较高。以大孔和大中孔综合评价参数为主要指标的低渗储层分类标准,将研究区低渗储层划分为三种类型,其中Ⅰ类、Ⅱ类储层大中孔较为发育,储层物性较好,大孔、大中孔综合评价参数值分别大于7、10,可动流体饱和度相对较高,普遍在65.75%以上;Ⅲ类储层物性相对较差,大孔和大中孔综合评价参数值较小,孔隙结构复杂,可动流体饱和度相对较低。该结果为海上低渗气田经济有效开发提供指导。