Stochastic surface modeling of deepwater depositional systems for improved reservoir models

High resolution reservoir models are often required for resource assessment and reservoir management. The reservoir models must reproduce geologically realistic heterogeneity that may affect predictions. An important heterogeneity in many deepwater depositional systems consists of facies variations controlled by geological events that lead to lobe geometries. A surface-based geostatistical scheme is presented to model high resolution lobes and their associated stacking patterns in a geometrically realistic manner. The lobes are constrained to match well data. Facies, porosity and permeability are then modeled within the lobe framework. Application to a reservoir with 36 wells demonstrates the practical applicability of the approach. This surface-based method may be readily extended to model other geometries in various reservoir settings.     

PETROPHYSICAL CHARACTERISTICS OF THE MESSINIAN ABU MADI FORMATION IN THE BALTIM EAST AND NORTH FIELDS,OFFSHORE NILE DELTA,EGYPT

Baltim East and North fields in the offshore Nile Delta produce gas‐condensate from accumulations located in the northern portion of the Abu Madi palaeovalley. The hydrocarbons in the Abu Madi Formation are present in sandstone reservoir units referred to as the Level III Main and Level III Lower. In this paper, the petrophysical characteristics of these reservoir units in the Baltim area are described using data from wireline logs (gamma‐ray, density, neutron, sonic and resistivity) from fourteen wells and core data from one well. Results of wireline log and core analyses indicate that the Level III Main can subdivided into two sandstone‐dominated intervals (both interpreted as sandbar deposits) separated by a shale‐rich interval which is a partial barrier to fluid flow. Effective porosity is 9–18.5% and permeability 40–100 mD. Sandstones in the Level III Lower are interpreted as braided channel facies and have effective porosity of 12.5–22% and permeability of 100–500 mD. Isoparametric maps for the Abu Madi Formation sandstone reservoirs based on log and core interpretations show the influence of depositional facies on petrophysical characteristics and can be used to assess possible targets for future exploration and development.     

高分辨率地震约束相建模

以委内瑞拉F油田Z油藏作为研究实例，利用测井资料约束地震数据，建立纵高分辨的三维地球地震波阻抗模型，再用随机反演地震三维数据体和井资料约束随机相建模过程，大大降低了相模型的不确定性；相控建模产生一系列孔隙度及渗透率的实现，在网格粗化后进行了流线模拟，优选出忠实于生产动态资料的实现。经流线模拟与注水动态比较，相控建模－岩石物理参数建模－网格粗化－快速优选（流线模拟）一体化建模产生的岩石物理参数模型与地质，测井，地震，动静态资料比较吻合，图3参3（周丽清摘）。     

苏丹M盆地P油田退积型辫状三角洲沉积体系储集层综合预测

在储集层预测中如何有效运用地球物理技术，是储集层预测中所面临的难题。在对苏丹M盆地P油田退积型辫状三角洲沉积体系储集层预测中，总结出结合各种地球物理方法综合预测储集层的研究思路。首先根据已钻井的岩心和录井资料，划分典型井取心段沉积微相，确定研究区目的层沉积环境；然后，以取心段沉积相特征为依据，结合相应的测井信息，将研究区所有井目的层划分为辫状三角洲平原亚相、辫状三角洲前缘亚相和前辫状三角洲亚相；最后，运用沉积相研究结果，结合高精度井震标定技术，确定主力储集层段地震反射特征，划分地震相，同时运用地震反演技术研究不同砂体的展布特征及其发育期次，并寻找不同砂体的物源方向，对储集层进行综合预测。图6参11     

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.     

川东北元坝地区飞仙关组二段鲕滩储层预测

川东北元坝地区飞仙关组二段具有广阔的勘探潜力。本文在分析元坝地区飞仙关组二段鲕滩储集层地质特征的基础上,利用三维地震资料,进行储集层精细标定、储集层地质建模与正演,确定储集层的地震响应特征;采用古地貌分析、地震相划分及地震属性分析等手段,确定储集层发育的有利相带和储层宏观展布,并以此为基础,应用稀疏脉冲约束波阻抗反演对储集层孔隙度及有效厚度进行精细预测,建立了一套鲕滩储集层的预测方法,预测了元坝地区飞仙关组二段鲕滩储集层的分布,通过与已完钻井储层厚度及孔隙度的对比,证实了预测结果的正确性。     

3D seismic and formation micro-imager (FMI) integrated study to delineate depositional pattern of Abu Madi (Upper Miocene) clastic reservoir rocks in El-Wastani gas field,onshore Nile Delta,Egypt

Ten wells (EW-4, EW-5, EW-6, EW-7, EW-8, EW-9, EW-10, EW-12, EW-13 and EW-15) were interpreted using the composite well logs, data of core analysis, gamma-ray logs, formation micro-imager logs (FMI), and 3D seismic data in SEGY format to understand the stratigraphy of the onshore, Nile Delta, Egypt.The amplitude analysis of 3-D seismic horizon slice of Lower Abu Madi rock unit together with the lithostratigraphic correlation through the study area depending on the gamma-ray log “HSGR” (left to right increasing), and the identification of type of bed geometry, nature of bed contacts, type of the sedimentary structures and the dominant formative paleocurrents by using some available borehole micro-resistivity images (FMI) and core photos. All of these techniques are used together to define the different depositional facies and depositional environment of the Messinian clastics (Lower Abu Madi rock unit), which is considered to be the main reservoir in the El-Wastani gas field, onshore Nile Delta, Egypt.The present study of depositional pattern of the Upper Miocene clastics reservoir (Lower Abu Madi rock unit) revealed that it is represented by high sinuous meandering channels or paleo-valley and three types of fluvial facies were defined; channel fill, channel margin, and floodplain basin.     

沉积相对岩石物理特性从岩心到录井尺度粗化的控制及在石油勘探中的意义

有效的粗化岩石物理特性及跨尺度对比对油藏描述及模拟有极重要的意义。本文用统计数学方法探讨沉积过程和沉积相对油藏岩石物理特性跨尺度对比的影响。对单一沉积过程及渐变水动力所产生的油藏(例如滨岸相)岩心与录井的岩石物理特性可以在较大范围内交叉对比。录井的岩石物理特性能比较实际的反映岩心的特性。对多个沉积过程及突变型水动力所产生的油藏(例如三角洲相)岩心与录井的岩石物理特性交叉对比性差。而且录井的岩石物理特性不能实际的反映岩心的特性尤其是对薄层(<1m)泥沙岩交互相油藏。     

SEQUENCE STRATIGRAPHIC ANALYSIS OF THE MID‐CRETACEOUS MISHRIF FORMATION,SOUTHERN MESOPOTAMIAN BASIN,IRAQ

The middle Cenomanian – early Turonian Mishrif Formation, a major carbonate reservoir unit in southern Iraq, was studied using cuttings and core samples and wireline logs (gamma‐ray, density and sonic) from 66 wells at 15 oilfields. Depositional facies ranging from deep marine to tidal flat were recorded. Microfacies interpretations together with wireline log interpretations show that the formation is composed of transgressive and regressive hemicycles. The regressive hemicycles are interpreted to indicate the progradation of rudist lithosomes (highstand systems tract deposits) towards distal basinal locations such as the Kumait, Luhais and Abu Amood oilfield areas. Transgressive hemicycles (transgressive systems tract deposits) represent flooding of the shallow carbonate platform and are recorded in oilfields such as Amara, Halfaya and Zubair. A sequence stratigraphic framework has been constructed for the Mishrif Formation based on correlation of the transgressive and regressive hemicycles which are separated by maximum flooding surfaces. Three third‐order sequences are identified which show lateral and vertical facies variations depending on relative sea‐level changes. Sequence boundaries are characterized by karstic, exposure and drowning features. Middle Cenomanian – Turonian eustatic sea‐level changes together with regional‐scale tectonic deformation of the Arabian Plate controlled the availability of accommodation space and therefore the depositional profile during development of each sequence. Both of these factors controlled the maximum flooding surfaces and sequence boundaries which have been identified. The sequence stratigraphic key surfaces presented in this study represent typical candidate horizons or datum surfaces for future seismic or resevoir modelling studies. Also, lateral facies variations in each transgressive‐regressive sequence and associated carbonate bodies (i.e. prograding shelf margin, forced regressive wedge) may form important stratigraphic traps in the Mesopotamian Basin.     

塔里木盆地奥陶系碳酸盐岩大型缝洞集合体定量描述

大型缝洞集合体的定量描述是在中低丰度缝洞型碳酸盐岩储层中实现少井高效开发的重要手段。 缝洞型碳酸盐岩储层复杂、多期的地质成因及其内部强烈的非均质性,使得常规建模手段难以直接应用 于该类储层。以塔里木盆地哈拉哈塘油田典型区块为例,结合地质体特征和地震相分析,运用聚类分析 方法,实现了大型缝洞集合体的几何结构建模;针对缝洞型碳酸盐岩储层测井资料少、内部结构复杂和 非均质性强的特点,将地质统计学地震反演技术应用于储层岩相和孔隙度建模中,建立了哈拉哈塘油田 缝洞集合体静态模型,实现了对其的定量地震描述;进一步利用单井与井组内动态数据,修正大型缝洞 集合体模型的规模、边界和连通性,完成了对大型缝洞集合体的动静态精细刻画。研究成果指导了基于 大型缝洞集合体的井位部署及开发。     

DIAGENESIS OF TIGHT‐GAS SANDSTONES IN THE LOWER CRETACEOUS DENGLOUKU FORMATION,SONGLIAO BASIN,NE CHINA: IMPLICATIONS FOR RESERVOIR QUALITY

Non‐marine tight‐gas sandstones have not been studied intensively in terms of diagenesis and reservoir‐quality evaluation. This paper investigates the sandstones in the Lower Cretaceous Denglouku Formation in the Songliao Basin, NE China, which comprise a tight reservoir for natural gas. Core samples of the sandstones were obtained from eight wells located in two gasfields and were described in terms of lithology and sedimentology with the aid of wireline log interpretation; other data included thin section petrography, and X‐ray diffraction analyses and scanning electron microscopy. The sandstones mainly comprise moderate‐ to well‐sorted, fine‐ to medium‐grained feldspathic litharenites deposited in braided fluvial to braid‐delta settings under warm, arid to semi‐arid climatic conditions. Diagenetic processes which have affected the sandstones include compaction and cementation by calcite, dolomite, ferroan calcite, quartz, chlorite and illite. Porosity characteristics of the sandstones are closely linked to depositional facies, and the sandstones can be divided on the basis of sediment textures and depositional facies into three groups which have distinctive diagenetic features. The best reservoirs are represented by relatively coarse‐grained sandstones deposited in braid‐delta mouth bars and distributary channels and braided fluvial channels; these sandstones have relatively high porosity (up to 5%) and contain large amounts of chlorite and illite pore‐lining cements but relatively minor carbonate cement. A reservoir quality prediction model is proposed and incorporates textural, depositional and diagenetic attributes. The model will help to identify sweet spots in non‐marine tight‐gas sandstones elsewhere, and will contribute to more effective field development.     

砂岩成岩相地震预测——以松辽盆地齐家凹陷青山口组为例

以松辽盆地齐家凹陷青山口组为例,探讨应用地震沉积学和实验室岩心分析手段,采用常规三维地震资料预测砂岩成岩相的可行性。用地震资料划分地层和成岩相单元、建立岩心成岩相与地震属性的联系以及寻找有效的地震成岩相成图方法,是地震成岩相研究的3个关键步骤。井-震高分辨率层序分析和地层切片的制作可提供储集层尺度(20 m)成岩相单元的合理载体。砂岩成岩相分析和成岩序列的建立可揭示影响储集层质量的最重要因素——成岩作用。通过储集层参数和岩石物性分析可进一步了解成岩作用和波阻抗的关系并筛选适用地震检测的主要成岩作用。地震岩性体(如90°相位地震体)转换提供了成岩相的振幅(波阻抗)检测信号,用地震岩性体制作的地层切片可用于识别沉积相。在沉积相图上分析沉积相、波阻抗和成岩相的关系,可最终形成地震成岩相图。对青山口组泥质胶结砂岩和方解石胶结砂岩的实际分析表明,虽然砂岩成岩相地震检测尚处于起步阶段,但目前用常规三维地震资料预测砂岩成岩相是可行的。     

RESERVOIR POTENTIAL OF A LACUSTRINE MIXED CARBONATE / SILICICLASTIC GAS RESERVOIR: THE LOWER TRIASSIC ROGENSTEIN IN THE NETHERLANDS

The Lower Triassic Rogenstein Member of the Buntsandstein Formation produces gas at the De Wijk and Wanneperveen fields, NE Netherlands and consists mainly of claystones with intercalated oolitic limestone beds. The excellent reservoir properties of the oolites (φ= 20‐30%; k = 5‐4000 mD) are predominantly controlled by depositional facies. Oolitic limestones are interpreted as the storm and wave deposits of a shallow, desert lake located in the Central European Buntsandstein Basin. The vertical sequence of lithofacies in the Rogenstein Member indicates cyclic changes of relative lake level. The reservoir rock is vertically arranged in a three‐fold hierarchy of cycles, recognised both in cores and wireline logs. These cycles are a key to understanding the distribution of reservoir facies, and are used as the basis for a high‐resolution sequence stratigraphic correlation of the reservoir units. Slight regional‐scale thickness variations of the Rogenstein Member (in the order of tens of metres) are interpreted as the effects of differential subsidence associated with the inherited Palaeozoic structural framework. The depositional basin can be subdivided into subtle palaeo‐highs and ‐lows which controlled facies distribution during Rogenstein deposition. Oolitic limestones show their greatest lateral extent and thickest development in the Middle Rogenstein during large‐scale maximum flooding. Potential reservoir rocks (decimetre to metres thick) are present in the NE Netherlands, in particular in the Lauwerszee Trough and the Lower Saxony Basin, where abundant gas shows of 200 ‐ 4000 ppm CH₄ have been recorded. Preserved primary porosity is interpreted to be a result of rapid burial in subtle depositional palaeo‐lows in this area. The thickest, amalgamated oolite intervals (tens of metres thick) occur in the eastern part of the Central Netherlands Basin. Because of poor reservoir properties, other areas appear to be less promising in terms of Rogenstein exploration potential.     

DEPOSITIONAL FACIES,PORE TYPES AND ELASTIC PROPERTIES OF DEEP‐WATER GRAVITY FLOW CARBONATES

Quantitative petrographic analyses of deep‐water resedimented carbonates from the Gargano Peninsula (SE Italy) were integrated with petrophysical laboratory measurements (porosity, P‐and S‐wave velocities) to assess the impact of sedimentary fabrics and pore space architecture on velocity‐porosity transforms. Samples of Upper Cretaceous carbonate came from the Monte Sant'Angelo, Nevarra and Caramanica Formations and can be classified into four depositional facies associations: F1, lithoclastic breccias; F2, bioclastic packtones to grainstones; F3, interbedded grainstones‐packstones and wackestones; and F4, (hemi‐) pelagic mudstones. Five pore type classes were distinguished: I and II, dominant intercrystalline microporosity; IIIa, dominant intergranular macroporosity; IIIb, dominant mouldic macroporosity; and IIIc, mixed intergranular and mouldic macroporosity. Pore type was found to strongly control velocity‐porosity transforms, unlike depositional facies associations. The equivalent pore aspect ratio (EPAR), derived from differential effective medium models, is proposed to identify pore types from elastic properties. The EPAR originates from the bulk modulus or shear modulus of the samples (K‐ and μ‐EPAR, respectively). Regardless of porosity values and depositional facies, microporous samples (type I) and samples with dominant intergranular porosity (type IIIa) are characterized by low values of K‐ and μ‐EPAR (<0.22) and by K‐EPAR > μ‐EPAR By contrast, samples with dominant mouldic porosity (type IIIb) display high values of K‐ and μ‐EPAR (>0.25 and 0.4 respectively) and K‐EPAR < μ‐EPAR. High permeability limestones with dominant intergranular porosity cannot be discriminated from low permeability microporous carbonates. The petrophysical classes derived from elastic properties are shown to be distinct from reservoir property‐driven rock types. In the present case, a seismic‐based poro‐elastic model does not match the reservoir property model. Hence, a sedimentary facies model for the studied carbonates cannot accurately represent the petrophysical properties, which are determined by pores types and pore network architecture.     

NEURAL NETWORK PREDICTION OF PERMEABILITY IN THE EL GARIA FORMATION, ASHTART OILFIELD, OFFSHORE TUNISIA

The Lower Eocene El Garia Formation forms the reservoir rock at the Ashtart oilfield, offshore Tunisia. It comprises a thick package of mainly nummulitic packstones and grainstones with variable reservoir quality. Although porosity is moderate to high, permeability is often poor to fair with some high permeability streaks. The aim of this study was to establish relationships between log‐derived data and core data, and to apply these relationships in a predictive sense to uncored intervals. An initial objective was to predict from measured logs and core data the limestone depositional texture (as indicated by the Dunham classification), as well as porosity and permeability. A total of nine wells with complete logging suites, multiple cored intervals with core plug measurements together with detailed core interpretations were available. We used a fully‐connected Multi‐Layer‐Perceptron network (a type of neural network) to establish possible non‐linear relationships. Detailed analyses revealed that no relationship exists between log response and limestone texture (Dunham class). The initial idea to predict Dunham class, and subsequently to use the classification results to predict permeability, could not therefore be pursued. However, further analyses revealed that it was feasible to predict permeability without using the depositional fabric, but using a combination of wireline logs and measured core porosity. Careful preparation of the training set for the neural network proved to be very important. Early experiments showed that low to fair permeability (1–35 mD) could be predicted with confidence, but that the network failed to predict the high permeability streaks. “Balancing ” the data set solved this problem. Balancing is a technique in which the training set is increased by adding more examples to the under‐sampled part of the data space. Examples are created by random selection from the training set and white noise is added. After balancing, the neural network's performance improved significantly. Testing the neural network on two wells indicated that this method is capable of predicting the entire range of permeability with confidence.     

SEQUENCE STRATIGRAPHY AND RESERVOIR CHARACTERISTICS OF THE TURONIAN-CONIACIAN KHASIB FORMATION IN CENTRAL IRAQ

Bioturbated chalky limestones of the Khasib Formation (Upper Turonian – Lower Coniacian) form potential reservoir rocks at oilfields and structures in central Iraq. Core and cuttings samples and wire-line logs from wells in the East Baghdad, Balad, Samarra and Tikrit fields (wells EB-77, EB-57, Ba-1, Ba-2, Sr-1, Sr-2, and Ti-1) were used to investigate microfacies types and porosity evolution. Facies modelling was applied to predict the relationship between facies distribution and reservoir characteristics to construct a predictive geologic model which will assist future exploration in central Iraq. Microfacies analysis and electrofacies identification and correlations indicate that the limestones of the Khasib Formation were deposited in a ramp setting. The ramp developed over the distal margin of the Upper Cretaceous proforeland basin, adjacent to the evolved forebulge. Inner ramp facies are characterized by carbonate bank bioclastic packstones intercalated with lagoonal green shales. Middle ramp facies dominate the Khasib Formation and consist of bioturbated, chalky, dolomitic and bioclastic limestones. Bioclasts include benthic and planktonic foraminifera. Intense Thalassinoides and less common Palaeophycus bioturbation has enhanced the porosity of this facies. Outer ramp deposits consist of alternating mid-ramp bioturbated bioclastic chalky limestones and argillaceous and marly limestones. The latter contain basinal bioclasts including planktonic foraminifera, oligosteginids, dwarf rotaliids, and sponge spicules. Sequence stratigraphic analyses of the Khasib Formation indicate that it represents a third-order depositional cycle. At the base is a type 1 sequence boundary which separates it from the underlying LST deposits of the Kifl Formation. Shaly and argillaceous limestones in the lower part of the Khasib Formation represent the early TST. These are overlain by a thick, deepening-upwards succession of outer ramp facies. The maximum flooding surface is represented by a thin and extensive horizon of Oligosteginal limestones with Palaeophycus bioturbation. HST deposits are represented by aggradational build-ups of bioturbated chalky dolomitic limestones, followed by progradational late HST shales and limestones. The boundary with the overlying Tanuma Formation is a type 2 sequence boundary. Bioclastic packstones and intensively bioturbated (Thalassinoides) bioclastic limestones of the mid-outer ramp are the primary source of fabric-selective porosity which is greatly enhanced by diagenetic overprints. These two units constitute the prime target for future exploration in central Iraq.     

地质统计分析方法在鲕滩储层预测中的应用

地质统计分析方法实现了地震属性到储层岩石物性参数的转换，可以获得可靠的预测结果。针对LJZ构造鲕滩储层层多、层薄、纵横向分布不均匀等特点，利用地质统计分析方法进行了飞仙关组鲕滩储层定量预测。提取了均方根振幅和平均振幅等6种地震属性参数，选取相关性高的属性参数与井数据建立统计关系，经过内插外推得到井间物性参数平面图。地质统计分析方法预测的鲕滩储层厚度及孔隙度与井资料吻合程度较高，储层的平面分布与速度反演方法预测的鲕滩储层横向分布规律一致。     

FLOW UNIT CLASSIFICATION FOR GEOLOGICAL MODELLING OF A HETEROGENEOUS CARBONATE RESERVOIR: CRETACEOUS SARVAK FORMATION, DEHLURAN FIELD, SW IRAN

Flow unit classifications can be used in reservoir characterization and modelling of heterogeneous carbonate reservoirs where there is uncertainty and variability in the distribution of porosity and permeability. A flow unit classification requires the integration of geological and petrophysical data, together with reservoir engineering and production data. In this study, cores and thin sections from the upper part of the Cretaceous Sarvak Formation at the Dehluran field, SW Iran, were studied to identify flow units which were then used in reservoir modelling. Eight flow units were defined based on a classification of depositional environments and diagenetic processes and an evaluation of porosity and permeability. In lagoonal deposits, two flow units were distinguished in terms of dissolution effects (i.e. low or high values of vuggy porosity). In shoal/reef deposits, three flow units were distinguished in terms of cementation volumes and grain frequency. In open‐marine deposits, two flow units were identified with different degrees of dissolution; while intrashelf basinal deposits were characterized by a single flow unit with no observable reservoir potential. Each flow unit was characterized by unique values of porosity, permeability, water saturation and pore throat distribution. Grain‐supported deposits from high energy depositional environments (shoals) had the highest porosities and permeabilities. However, these rocks were frequently cemented with a consequent reduction in porosity and permeability. By contrast, low permeability mud‐supported deposits had undergone dissolution, forming highly permeable flow units. Capillary pressure curves from mercury injection were used to determine the distribution of pore throat sizes and the pore characteristics of the flow units, and were used to give an indication of the productivity of each flow unit. Flow units were modelled using a pixel‐based modelling tool. Modelled reservoir characteristics were mainly controlled by facies changes in the vertical direction, and by diagenetic variations in the horizontal direction. Input values for the geometry of the flow units were based on information from geological and diagenetic models of the reservoir, and from thickness maps of the flow units derived from well data.     

FACIES AND POROPERM CHARACTERISTICS OF A CARBONATE SHOAL (MUSCHELKALK, SOUTH GERMAN BASIN): A RESERVOIR ANALOGUE INVESTIGATION

Outcrop analogue investigations contribute to the understanding of the architecture and behaviour of subsurface hydrocarbon reservoirs. This study was designed to provide input for static reservoir modelling of shoal bodies on carbonate ramps. We investigated an oolitic and shelly carbonate shoal of Late Muschelkalk (late Ladinian) age, about 30 km long and 15 km wide, exposed in a series of quarries in southern Germany. The dimensions of this shoal body correspond to both modern analogues in the Persian Gulf and to oilfields in the Middle East. Fifteen outcrop locations were chosen to cover the entire shoal. A regional correlation based on facies, sequence analysis and outcrop gamma‐ray logs was used as a framework for mapping the distribution of shoal (i. e. reservoir) facies and associated reservoir properties. Three major depositional environments were recognized: foreshoal, shoal and backshoal. In each environment, specific vertical facies successions composed of thick shallowing‐upward units and thin deepening‐upward units forming metre‐scale cycles were deposited. These small‐scale cycles are stacked and form large‐scale shallowing and deepening trends. Shoal facies developed preferentially in the regressive parts of small‐scale cycles and were found to be laterally continuous over distances of at least several kilometres. Porous intervals within the shoal facies are concentrated along the tops of the small‐scale shallowing‐upward cycles. The porous intervals in successive small‐scale cycles increase in thickness and in absolute values of porosity upwards through the large‐scale shallowing trend. Separate vug pore types are characterized by relatively low permeabilities (0 to about 10 mD) in spite of the high porosity (up to 20%). The combined occurrence of separate vug and interparticle porosity leads to higher permeabilities (tens of mD). Isolines of porosity, permeability and net/gross follow the contours of the carbonate shoal complex. The highest values of porosity appear more or less at the centre of the shoal, while the highest values of permeability are found at the shoal margins. The distribution of maximum porosity and maximum permeability zones are thus controlled by the cyclic seaward‐stepping and landward‐stepping of the shoal body. The systematic variations in extent, stacking pattern and related petrophysical characteristics of the carbonate shoal bodies may be used for modelling shoal reservoirs in producing oilfields.