EFFECT OF MICRITE CONTENT ON CALCITE CEMENTATION IN AN UPPER JURASSIC CARBONATE RESERVOIR,EASTERN SAUDI ARABIA

Cementation is a primary factor reducing the porosity of carbonate rocks. It is a challenge to accurately model cementation for reservoir quality prediction because cementation is often a syndepositional process. In addition, cementation requires fluid flow to transport chemical species for precipitation within the pore spaces in a sediment. The development of fully‐coupled depositional‐hydrogeochemical models for cementation prediction is desirable, but the parameters which control the extent of cementation need to be identified and evaluated. This study uses petrographic data from 583 carbonate samples from 15 wells in an Upper Jurassic (Kimmeridgian) reservoir at a giant oilfield in eastern Saudi Arabia to investigate the controlling effects of micrite content on cementation in carbonate rocks. The results indicate that the amount of cement decreases with increasing micrite content in the carbonate rocks analysed. In addition, a modified Houseknecht method has been developed to assess the relative fractions of porosity reduction in carbonate sediments due to compaction and cementation. The method highlights variations in depositional porosity for different rock textures and distinguishes microporosity from interparticle porosity. In the studied samples, the total porosity loss due to compaction and cementation is generally less than 45%, and samples lose more porosity due to compaction than cementation. The relative importance of compaction and cementation in reducing porosity is different for different rock textures: wackestones and mudstones lose porosity mostly as a result of compaction, while grainstones, mud‐lean packstones and packstones lose porosity due to both compaction and cementation.     

MICROPOROSITY IN THE UPPER JURASSIC ARAB‐D CARBONATE RESERVOIR,CENTRAL SAUDI ARABIA: AN OUTCROP ANALOGUE STUDY

This study investigates microporosity in an outcrop analogue of the Upper Jurassic (Kimmeridgian) Arab‐D carbonate reservoir in central Saudi Arabia, integrating outcrop facies analysis, petrographic and SEM data and statistical analyses. At the study location in Wadi Nisah, the outcropping succession includes the uppermost Jubaila Formation and the entire Arab‐D Member of the Arab Formation which together comprise the Arab‐D reservoir interval. The succession is composed of eight lithofacies which can be grouped into three lithofacies associations based on their depositional environments. The stromatoporoid lithofacies association includes dolomitic mudstones, dolomitic wackestones and stromatoporoid wackestones and packstones; the skeletal bank lithofacies association includes burrowed fossiliferous wackestones and peloidal fossiliferous grainstones; and the tidal flat lithofacies association comprises laminated mudstones, wave‐rippled sandy grainstones, and supra‐ and intertidal muds with rip‐up clasts. The lithofacies were classified into mud‐dominated, grain‐dominated and dolostone textural groups. Microporosity and associated permeability in the analysed samples (n = 125 for porosity and n = 61 for permeability) range from 0.11% to 4.8 % and 0.36 to 4.35 mD, respectively. Three types of microporosity were observed: (i) between macro‐ and micro‐sparry calcite crystals; (ii) between micrites of varying morphologies; and (iii) within macro‐sized dolomite crystals. Microporosity distribution was controlled by sparry calcite cement, micrite crystal size, sorting and shape, and the presence of dolomite crystals. Statistical analyses of microporosity and associated permeability show non‐normal distributions for both variables. Coefficients of variation indicated high variability for porosity and permeability, which may be attributed to the high degree of heterogeneity in the pore system. In general there was a poor correlation between microporosity and permeability, but the correlation improved when visualized for individual textural groups.     

LITHO- AND MICROFACIES OF UPPER JURASSIC CARBONATE ROCKS OUTCROPPING IN CENTRAL SAUDI ARABIA

A study of surface sections of Upper Jurassic rock units near the city of Riyadh has revealed a total thickness of 500 m. These rock units are the Tuwaiq Mountain Limestone, Hanifa Formation, Jubaila Limestone, Arab Formation and Hith Anhydrite. The characteristic microfacies of Tuwaiq Mountain Limestone include spicular biomicrites in the lower part of the formation, and corals, stromatoporoids and algal biomicrites in the upper part. The characteristic microfacies of the Hanifa, Jubaila and Arab Formations include spicular biomicrites with some argillaceous shales alternating with pelsparities and oosparites. Conglomeratic micrites, dolomites and breccia are found in the upper Jubaila Limestone and the Arab Formation.
The total thickness of these rock units increases in the east to more than 900 m where the Arabian and Gotnia Basins are defined. Central Saudi Arabia is best described as being the site of differential carbonate shelf deposition during Upper Jurassic time. Intra-shelf basins with euxinic conditions were formed. Over these basins, petroleum source rocks were deposited within each rock unit.     

MINERALOGICAL, PORE AND PETROPHYSICAL CHARACTERISTICS OF THE DEVONIAN JAUF SANDSTONE RESERVOIR, HAWIYAH FIELD, EASTERN SAUDI ARABIA

Throughout the subsurface of the Arabian Peninsula, the approximately 460ft thick, Devonian Jauf Formation generally consists of well-compacted, low-porosity sandstones and shales, but it also includes friable and highly porous sandstones which form significant gas and condensate reservoir intervals. The mineralogy and pore properties of these reservoir intervals at the Hawiyah field (part of the giant Ghawar structure) were studied by integrating petrographic data with petrophysical measurements of reservoir sandstone samples.
The reservoir sandstones are mainly composed of quartz arenites containing small amounts of altered potassium feldspar grains, authigenic illite and chlorite. Based on the pore types, which reflect the habits of the intergranular clays, three reservoir sandstone types have been defined: Type A, characterized by macroporosity; Type B, with microporosity; and Type C, with combined laminations of Types A and B. The dominance of pore-lining clay (as in Type A) or pore-filling clay (as in Type B) is the principal factor controlling the petrophysical properties of the samples. Types A and C sandstones contain macro pores, but irreducible water saturation is high (25 to 45%) compared to clean samples elsewhere, because of the presence of micropores associated with clay. In Type B sandstones the irreducible water saturation is commonly greater than 40% because all the pores spaces are in the microporosity range. The irreducible water saturation in Type B sandstones increases rapidly as porosity decreases. When porosity is less than 10%, the corresponding permeability is 0.2 mD, but no economic production can be expected because water saturation is as high as 100%. In the producing intervals, authigenic clays result in low electrical resistivity due to high water saturation; however, water-free gas is produced.     

DISTRIBUTION OF PETROPHYSICAL PARAMETERS IN THE CAMBRO-ORDOVICIAN DIBSIYAH MEMBER OF THE WAJID SANDSTONE,SW SAUDI ARABIA

The Cambrian-Ordovician Dibsiyah Member is the lowermost unit of the Wajid Sandstone, a major aquifer in SW Saudi Arabia. The Dibsiyah is present throughout most of south-central Arabia including the Rub'Al-Khali Basin where it is a potential exploration target and a reservoir for gas. The Member can be divided into Upper and Lower Units based on depositional facies. The Lower Unit is interpreted to have been deposited in a fluvial setting, whereas the Upper Unit, which displays abundant bioturbation, was deposited in shallow-marine conditions. Patterns of porosity and permeability distribution in the Dibsiyah Member were analysed statistically. In general, the Member exhibits a limited range of porosity values and a wide range of permeability values. Histograms show that the porosity distribution of both Lower and Upper Units are approximately normal, and that their corresponding vertical and horizontal permeability distributions are positively skewed. The coefficient of variation for porosity in both the Lower and Upper Units is less than 0.5 indicating that the porosity range is small. However, the horizontal and vertical permeability values are more variable due to the spatial distribution of architectural elements and sedimentary structures within both units. The dissolution of unstable minerals, together with inhomogenous grain packing and poor connectivity, has resulted in a variable permeability distribution.     

沙特阿拉伯天然气资源与利用现状

介绍了沙特阿拉伯丰富的天然气资源状况、其国家天然气系统(MGS)的建设情况,以及天然气利用现状和今后发展。该国在天然气利用方面的发展主要表现为：一是扩大天然气作为石油化工原料的利用,进一步发展石油化工;二是发展“天然气发展核心计划”,未来5年将有8家国际石油公司投资进行天然气勘探、生产和利用。     

DEPOSITIONAL AND DIAGENETIC BARRIERS,BAFFLES AND CONDUITS: PERMIAN – CARBONIFEROUS UNAYZAH RESERVOIR,NUAYYIM FIELD,CENTRAL SAUDI ARABIA

The Unayzah Formation is one of the most important Palaeozoic reservoir systems in Saudi Arabia. In the Nuayyim field, Central Saudi Arabia, it produces light, sweet crude oil and consists of three main reservoir units, in descending stratigraphic order: Unayzah A, B and C. These reservoir units include a wide range of depositional facies deposited under a variety of climatic conditions, from high‐latitude glacio‐fluvial to more temperate playa/lacustrine, floodplain and braided‐fluvial to hot‐arid aeolian environments. Together with the diagenetic changes superimposed on the various depositional facies, this has produced complex reservoir heterogeneity. The effects of this diagenetic and sedimentologic complexity on reservoir quality and compartmentalization are the subject of this paper. Approximately 816 ft of core and 611 core plug samples were examined from three wells which penetrate, completely or in part, the Unayzah reservoir. We combine petrographic and scanning electron microscope analysis with porosity and permeability data and calculated pore throat dimensions to identify fluid conduits, barriers and baffles to fluid flow. A rock classification scheme is proposed which takes into account whether the pore‐level control on fluid flow is due to depositional or diagenetic processes and the composition of depositional or diagenetic phases within the pores. Distinguishing depositional versus diagenetic controls on fluid flow is important for predicting the three‐dimensional geometry of conduits, barriers and baffles, and a priori knowledge of potential reactions between injected fluids and reservoir rocks is important for designing enhanced oil recovery fluids. In the three wells studied, it appears that the Unayzah reservoir is compartmentalized vertically due to the occurrence of diagenetic and depositional barriers and baffles. There is insufficient data to assess the lateral or areal extent of the barriers, baffles and fluid conduits, but the understanding of pore‐level controls on reservoir quality and the rock classification schemes introduced here will provide a starting point for future studies. These studies should combine well logs, seismic and engineering data with data presented here to assist mapping conduits, barriers and baffles across the field. The proposed classification schemes may also prove to be useful for assessing reservoirs in other fields both within Saudi Arabia and elsewhere.     

STATISTICAL DISTRIBUTIONS AND CORRELATIONS OF PETROPHYSICAL PARAMETERS IN THE ARAB-D RESERVOIR, ABQAIQ OILFIELD, EASTERN SAUDI ARABIA

The Upper Jurassic Arab-D is a complex carbonate reservoir present in the Eastern Province of Saudi Arabia. It has been subdivided into five zones on the basis of porosity. A statistical analysis of the extensive dataset from the three productive zones in the reservoir unit (Zones 1, 2 and 3) has shown that patterns of well-log porosity and core porosity distributions are strikingly similar in each zone, but that the means are not. Consistently higher mean values observed in core distributions can be explained by a possible bias in core selection and/or differences in the measurement conditions. The results also show that each zone has a distinctive pattern of porosity distribution, reflecting its general lithological character.
The corresponding distributions of vertical and horizontal core permeability are similar, but the means of horizontal permeability in Zones 1 and 2 are higher than the corresponding means of vertical permeability. The reverse is true for Zone 3, in which mean vertical permeability is slightly higher than horizontal permeability. This is probably due to the presence of vertical hairline fractures, which were frequently observed in mud-dominated fades in Zone 3.
The permeability distribution for each zone is generally consistent with the corresponding porosity distribution, reflecting a degree of correlation between porosity and permeability. However, semi-log plots of core porosity versus core permeability indicate a relatively poor correlation between these variables, with the correlation coefficient being less than 0.7 for all zones. Separate correlation plots for each lithology within Zone 1 indicate that the lithological control on porosity is not very significant in this zone.     

沙特B区块致密砂岩气层保护技术研究

沙特B区块SAHRA储层孔隙度、渗透率低,平均孔喉中值半径小于0.1 μm,属于典型的致密砂岩气层.认清储层损害机理,设计合理的保护储层的钻井液体系是致密砂岩气藏高效开发的前提.敏感性实验研究结果表明,该储层存在中等偏弱速敏、中等偏弱的水敏和盐敏、以及弱的酸敏和碱敏,水锁程度为中等.针对储层损害特征,选用抗温、低滤失的无黏土KCl钻井液体系,为减轻水锁伤害,在钻井液体系中加入SPAN-80.室内实验结果表明,钻井液污染岩心后气测返排渗透率恢复值可达到75%以上.现场应用储层保护效果良好,ATNB-2井SARHA储层表皮系数为-2.     

油藏描述中求取特低渗储层渗透率的方法

精确求解地层渗透率是历代测井地质解释家十分棘手的问题.以前只是针对非特低渗储层作了大量的工作.本文针对辽河油田陈家洼陷南部浊积成因特低渗储层的渗透率进行研究,提出了一种建立其解释模型的有效方法,并在现场得到比较成功的应用,获得满意的效果.同时为当今测井研究前沿理论─-非线性与非均质测井理论提供了有力证据.     

准东帐北地区低渗透砂岩储集层裂缝分布规律

以准噶尔盆地东部帐篷沟地区为例, 研究了低渗透砂岩储集层中裂缝的分布规律。低渗透砂岩储集层中裂缝的间距常呈对数正态分布,并与岩层厚度密切相关,随着岩层厚度增加,裂缝间距增大。裂缝的间距、延伸长度及高度等参数之间具有较好的线性关系。低渗透砂岩储集层中裂缝的发育程度受岩相和构造应力双重因素的控制。     

油藏岩石渗透率合成方法

渗透率合成在石油储量计算、油田开发方案编制、油藏数值模拟等油藏工程研究中经常遇到,主要包括垂向上不同层段渗透率的合成以及沿渗流方向不同渗透率带渗透率的合成。根据达西定律,结合建立的渗流模型,经数学推导,得到两类渗透率的合成公式。其中,垂向上不同层段渗透率的合成公式与前人文献中一致;而沿渗流方向不同渗透率带的合成公式与前人有较大差别。经实测数据检验,用新推导的公式计算所得的结果误差为0.28%～53.5%,基本上在允许的范围之内。     

沙特鲁卜哈利盆地古生界石油地质特征及勘探潜力分析

利用石油地质学、储层地质学、油气成藏等理论分析了沙特境内的鲁卜哈利盆地古生界石油地质特征和油气勘探潜力。分析结果认为,鲁卜哈利盆地位于世界上油气最富集的波斯湾含油气区,长期处于构造背景稳定的克拉通内裂谷和被动大陆边缘,沉积层序齐全,沉积厚度超过10 km,纵向上形成众多生储盖组合,油气成藏条件优越。海西运动期间发生的挤压和隆升作用对盆地古生界圈闭的形成起了决定性作用,这些背斜、断背斜以及构造岩性圈闭在扎格罗斯山形成的挤压作用中受到一定程度的改造,到定型期基本早于志留系源岩油气大规模运移的时间,二者具有良好的配置关系。鲁卜哈利盆地古生界目前处于勘探初期,比较已经发现的储量和USGS统计的古生界中待发现储量,类比盆地北部中阿拉伯地质省的勘探现状,预示该盆地古生界有很好的油气勘探前景。      

核磁技术在轮南奥陶系碳酸盐岩储层评价中的应用

现代核磁共振测井技术的发展为提高利用测井资料进行油气层评价解释的精度提供了一种新的有效的手段;对于碳酸盐岩等复杂岩性油气藏,由于其储集空间复杂、非均质性强等因素,用常规测井技术难以进行准确描述。岩心核磁共振基础实验分析研究是核磁测井资料采集、处理解释分析及应用的基础。本文从岩心核磁实验资料入手并结合核磁测井实例探索了核磁技术在碳酸盐岩的应用,并很好地解决了在储层评价及储层参数研究中存在的难点:含烃饱和度的计算、确定孔隙度下限值和区分束缚孔隙流体和可动孔隙流体,在复杂多样的碳酸盐岩储层中效果不错。     

低渗透油藏CO2混相驱提高采收率试验

大多数低渗透油藏注水开发效果差,为了验证CO2混相驱在此类油藏的适用性,掌握其提高采收率的程度,以大庆榆树林油田为依托,进行了原油的细管试验与微观试验、天然岩心的驱油试验以及油藏的数值模拟研究,确定了CO2与榆树林油田原油的最小混相压力,试验与数值模拟测试了不同驱替方式在天然岩心上的采收率,二者非常吻合。试验表明:CO2混相驱可以应用于榆树林油田;天然岩心试验无水混相驱可以提高采收率19个百分点以上,水气交替可以提高采收率10~19个百分点;注入1个气体的合适段塞可以减少水对混相的影响,更大程度提高采收率。该研究表明CO2混相驱可提高低渗透油藏开发效果。     

断陷盆地碳酸盐岩潜山储层模式——以渤海湾盆地济阳坳陷为例

断陷盆地碳酸盐岩潜山发育了裂缝型、溶蚀型和孔洞型3种基本储层类型。不同的储层类型具有各自独立的成因机制和发育规律,它们共同构成风化壳淋滤带、垂直渗流带、水平溶蚀带、内幕孔洞带、断裂溶蚀带和构造裂缝带等6个储集体发育带,在空间上组合成复式立体的断陷盆地碳酸盐岩潜山储层模式。     

FACIES HETEROGENEITIES AND 3D POROSITY MODELLING IN AN OLIGOCENE (UPPER CHATTIAN) CARBONATE RAMP,SALENTO PENINSULA,SOUTHERN ITALY

Appraisal of the volumes of fluid in a carbonate reservoir will typically require a reliable predictive model. This can be achieved by combining studies of well-exposed carbonate successions with 3D models in order to obtain reliable quantitative data. In this paper, we present a detailed outcrop study and a 3D porosity model of a well-exposed Oligocene carbonate ramp (Salento Peninsula, southern Italy) to investigate the nature of small-scale facies and porosity heterogeneities. Porosity and permeability in the ramp carbonates appear to be controlled by the original mineralogy of skeletal components and by depositional textures. The aims of the study were therefore to identify the factors controlling porosity development in an undeformed carbonate ramp; to model the scale-dependent heterogeneities characteristic of the facies associations; and finally to produce a 3D model of the porosity distribution. The upper Chattian Porto Badisco Calcarenite which crops out along the coast of the Salento Peninsula consists of six lithofacies ranging from inner ramp deposits to fine-grained outer ramp calcarenites. The lithofacies are: inner ramp small benthic foraminiferal wackestone-packstones associated with (i) sea grass meadows (SG) and (ii) coral mounds (CM) consisting of coral bioconstructions with a floatstone/packstone matrix; middle ramp (iii) large rotaliid packstones to wackestone-packstones (LR), (iv) rhodolith floatstone-rudstones (RF), and (v) large lepidocyclinid packstones (LL); and (vi) outer ramp fine-grained bioclastic calcarenites (FC). A total of 38 samples collected from six stratigraphic sections (A, B, D, J, E, LO), measured in the Porto Badisco ravine, were investigated to discriminate the types of porosity. Effective and total porosity was measured using a helium pycnometer. The 3D porosity modelling was performed using PETREL™ 2016 software (Schlumberger). Four main types of porosity were recognized in the carbonates: interparticle, intraparticle, vuggy and mouldic. Primary porosity (inter- and intraparticle) is limited to middle ramp lithofacies (LL and LR) and outer ramp lithofacies (FC), whereas secondary porosity (vuggy and mouldic) was present in both inner ramp lithofacies (CM and SG) and middle ramp red algal lithofacies (RF). In the Porto Badisco carbonates, stratigraphic complexity and the distribution of primary porosity are controlled by lateral and vertical variations in depositional facies. Significant secondary porosity was produced by the dissolution of aragonitic and high-magnesium calcite components, which are dominant in the sea-grass and coral mound facies of the inner ramp and in the rhodolith floatstone-rudstones of the middle ramp. 3D models were developed for both effective and total porosity distribution. The porosity models show a clear correlation with facies heterogeneities. However of the two models, the effective porosity model shows the best correlation with the 3D facies model, and shows a general increase in effective porosity basinwards in the middle ramp facies.     

轮南下奥陶统碳酸盐岩储层类型与测井响应

轮南地区下奥陶统碳酸盐岩主要的油气储集空间为裂缝、溶洞及晶间孔,组成裂缝型、裂缝—溶洞型及孔缝型3类储集岩层。不同的储集空间及不同类型的储层具有明显不同的测井响应特征。本文在综合钻井、取心资料及室内分析,测井资料的基础上,建立了区内碳酸盐岩储层识别与划分的标准,并对Ln1,Ln8井进行了储层划分与评价。     

FACIES ANALYSIS AND DEPOSITIONAL SEQUENCES OF THE UPPER JURASSIC MOZDURAN FORMATION, A CARBONATE RESERVOIR IN THE KOPET DAGH BASIN, NE IRAN

Upper Jurassic carbonates of the Mozduran Formation constitute the principal reservoir intervals at the giant Khangiran and Gonbadli gasfields in the Kopet Dagh Basin, NE Iran. These carbonates were investigated using detailed field studies and petrographic and wireline log analyses in order to clarify their depositional facies and sequence stratigraphy. Facies were interpreted to reflect deep basin, fore-shoal, shelf margin, lagoon, tidal flat and coastal plain depositional systems.
The Mozduran Formation is composed of six depositional sequences. Thickness variations were controlled by differential subsidence. Aggradation on the platform margin and reduced carbonate production in the deep basin together with differential subsidence resulted in the creation of a narrow seaway during the late Oxfordian. Petrographic studies suggest that Mozduran Formation carbonates had a low-Mg calcite mineralogy during the Oxfordian, and an aragonite to high-Mg calcite mineralogy during the Kimmeridgian. Reservoir pay zones are located in highstand systems tracts within the lower and middle Kimmeridgian depositional sequences. The rapid lateral thickness variations of these sequences were controlled by tectonic factors, leading to compartmentalization of the Mozduran Formation reservoir with the possible creation of stratigraphic traps, especially at the Khangiran field.     

煤系粗粒低渗储层自生粘土矿物特征及其对储层特性的影响——以焉耆盆地侏罗系三工河组油层为例

中国中西部侏罗系煤系粗粒低渗储层中自生粘土矿物含量高,尤其是高岭石矿物的相对含量较高。焉耆盆地下侏罗统三工河组储层研究表明,粘土总量和高岭石含量在不整合面下随深度加大而减少,而伊利石和绿泥石的含量却随深度增加而加大。相同深度下,长石成分含量较高、厚度较大的主河道砂体中高岭石含量普遍较高。煤系地层中酸性流体介质环境下的水岩相互作用对粘土矿物的产生起关键作用。焉耆盆地粘土矿物的大量存在加剧了此类储层的低渗透性;增加了储层潜在敏感性;严重影响了油田增产效果。