In this issue…

Vincent et al . (pp. 249–276) report on the reservoir characteristics of the Albian Mauddud Formation in the super‐giant Greater Burgan field of Kuwait, which comprises the separate Burgan, Magwa and Ahmadi oilfields. Data came from 26 wells with the detailed logging of over 900 ft of core and the petrographic and microfacies analysis of 113 core‐plug derived thin sections. The study focusses on the Carbonate Member of the Mauddud Formation whose thickness varies in the Greater Burgan area from ∼40 ft at wells in Ahmadi field to only ∼15 ft in the southern Burgan field, where however it still forms a prolific oil‐producing reservoir unit. The Member is interpreted to have been deposited on a large‐scale platform in the southern margin of NeoTethys within which the Greater Burgan area occupied a relatively proximal zone. Depositional environments interpreted from cores and thin sections ranged from outer to mid‐ and inner platform, the latter including both high energy (shoal and shoreline) and low energy (lagoonal) settings. The Carbonate Member is divisible into two low‐order (probably fourth‐order) cycles, the top of the upper cycle corresponding to a third‐order sequence boundary at the top of the Mauddud Formation. This boundary represents a long‐lasting exposure surface marked by irregular but prominent karst features including cavities and pipes up to metre scale. Macropores in the Carbonate Member were filled with calcite and ferroan dolomite cements during early and later stages of diagenetic modification. However microporosity in the middle part of the Member has been preserved and enhanced as a result of meteoric diagenesis, and the mud‐supported, inner platform carbonates which dominate this interval have porosity up to ∼35% although permeability is <100 mD. Oil emplacement into the Carbonate Member reservoir is inferred mostly to have taken place after dolomite cementation.

The paper by Kosakowski et al . on pp. 277–300 presents new organic geochemical data on Middle Miocene source rocks in the Polish sector of the external Carpathian foredeep, which lies to the north and NE of the Carpathian orogenic belt. Sandstones in the thick Middle Miocene “molasse” succession in the external foredeep form major reservoirs at a series of relatively small‐scale biogenic gasfields which have been developed since the 1920s. Over 100 gasfields have been discovered in the Polish sector of the external foredeep of which 85 are currently producing; the largest, Przemysl, has estimated recoverable gas reserves of 70 B m³. The molasse succession in the external foredeep also contains organic‐rich mudstone intervals (Badenian – Lower Sarmatian) with source rock potential. For this paper, core samples (n = 671) of these mudstones were recovered from 45 boreholes in the Polish sector of the external foredeep and underwent standard organic geochemical analyses, including Rock‐Eval screening and GC/GC‐MS for biomarker analyses. The source rock maturation history was modelled in 1D at nine well locations. The results were integrated with previously‐published data. Results show that in general the Middle Miocene samples analysed have moderate TOC contents (overall average: ∼0.7%) and contain mostly terrigenous Type III kerogen with minor Type II. The samples are in general thermally immature as indicated by both Rock‐Eval T_max (<430 ^oC) and biomarker parameters. The modelling results indicate that source rock burial was not sufficient for generation of thermogenic gas, and hydrocarbons are therefore inferred mainly to have been generated at shallow depths by biogenic processes. Generation of thermogenic gas may have occurred locally where the Middle Miocene source rocks have been buried to greater depths, for example as a result of overthrusting by the nappes of the Carpathian foldbelt.

Lacustrine mudstones of Early Cretaceous age are active source rocks in the intracontinental strike‐slip and extensional basins which make up the West and Central Africa Rift System (WCARS). Reservoir intervals are present in the overlying Upper Cretaceous and Paleogene successions. However in the Bongor Basin, southern Chad, which is the focus of the paper by Dou Lirong et al . on pp. 301–322, a phase of inversion‐related uplift dated as latest Cretaceous – early Paleogene removed the reservoir intervals which are present in other WCARS basins. Dou et al . characterise the petroleum habitat in the Bongor Basin from organic geochemical analyses of oil samples and source rocks (including GC and GC‐MS data), together with petrological and other studies of reservoir units. Exploration in the Bongor Basin began in the 1970s and by end‐2019 some 15 oil and gas fields had been discovered of which the largest (Great Baobab, discovered in 2009) has estimated in‐place reserves of 1.5 B brl oil. Petroleum is produced from reservoirs in the Precambrian crystalline basement and from feldspathic sandstones in the Lower Cretaceous synrift succession. In terms or stratigraphy, the reservoir sandstones occur both below and above organic‐rich shale source rocks in the Lower Cretaceous Mimosa and upper Prosopis Formations, which are several hundreds of metres or more thick. The source rocks contain Tyles I/II kerogen, interpreted to be dominated by aquatic (algal‐derived) organic matter which is of oil window maturity (R_o 0.6–1.2%). Mimosa and Prosopis Formation shales also form an efficient regional seal for oil and gas. These mature source rocks may serve as a reservoir for unconventional shale oil and possibly for shale gas in places.

Galushkin et al . (pp. 323–340) present the first part of a two‐part numerical modelling study of the poorly‐studied conjugate margins of SW Australia and East Antarctica. An initial phase of NW‐SE to north‐south lithospheric extension and rifting took place here during the Late Jurassic to Early Cretaceous, with break‐up between the Australian and Antarctic margins in the Turonian. A second phase of stretching and rapid sea floor spreading occurred in the Paleogene. The present paper investigates the subsidence and thermal histories of the Bremer sub‐basin in the Bight Basin, offshore SW Australia; Part 2 will consider the Mawson Sea Basin on the conjugate margin of eastern Antarctica. For both papers, Galushkin et al . used the GALO numerical modelling programme which simulates heat transfer in the crust and underlying lithosphere and asthenosphere to depths of up to 100 km, and which models tectonic subsidence over time. Phases of lithospheric extension and elevated heat flows are thereby identified and quantified. Input data for the paper came from a pseudo‐well in the Bremer sub‐basin where the stratigraphy had previously been established. Six seismic stratigraphic units identified here range from Upper Jurassic to Upper Cretaceous and are referred to as the Bremer 1 to Bremer 6 units. The subsidence and thermal histories at the pseudo‐well location were reconstructed, and the maturation history of potential source rocks was modelled. Maturation modelling suggested that synrift fluvial‐lacustrine mudstones in the Bremer 1 unit at the base of the sedimentary succession became thermally mature for hydrocarbon generation during the initial rift phase and are overmature at the present day. Maturation of potential source rocks in the overlying Bremer 2, 3 and 4 units occurred during the second phase of tectonically‐driven subsidence since 42 Ma with the generation of light and heavy oil, some of which may have been cracked to gas.

The petroleum system at the prolific oilfields in the Dezful Embayment, SW Iran, is fairly well understood as a result of detailed studies over the past decades. Thus source rocks in the Albian Kazhdumi and Paleogene Pabdeh Formations are thought to supply reservoirs in the Upper Cretaceous Sarvak Formation and the Oligocene‐Miocene Asmari Formation. The paper by Vatandoust et al . on pp. 341–358 investigates the charge history of the Asmari Formation at three oilfields located in simple anticlinal structures in the southern part of the Embayment. For the study, core samples of the Asmari Formation from seven wells were collected and doubly‐polished thin sections were prepared. Fluid inclusions in the Asmari carbonates were then carefully studied including under UV light and by Raman spectroscopy, and selected oil‐ and aqueous inclusions underwent microthermometric analysis with the measurement of homogenization temperatures (T_h). This data was then integrated with the burial history of the study area as detailed in a previous investigation. Fluorescence colours of oil‐bearing inclusions varied from yellow‐green to blue‐white, indicating the presence of oils derived from source rocks of different maturities. Likewise, measured T_h values for oil and aqueous solutions had distinctly bimodal distributions, indicating the presence of at least two oil charges. These oil charges were dated as ∼7.3 to 3.5 Ma and 3.5 to 2 Ma by integrating the fluid inclusion T_h measurements with the burial and maturation history. Modelling of the Kazhdumi and Pabdeh source rocks in the study area showed that neither formation was buried to sufficient depths for gas generation to occur. The observation of methane in gas‐bearing fluid inclusions may therefore indicate that oil‐to‐gas cracking has occurred, probably mostly as a result of Late Pliocene uplift at the structures studied.

在这个问题上…

文森特等 。（第249-276页）报告了科威特超大型大布尔干油田Albian Mauddud组的储层特征，该油田由单独的布尔甘，马格瓦和艾哈迈迪油田组成。数据来自26口井，对900英尺以上岩心进行了详细测井，并对113个岩心塞衍生的薄片进行了岩相和微相分析。这项研究集中于莫德杜德组的碳酸盐岩层，其厚度在大布尔干地区从Ahmadi油田的约40英尺到南部布尔干油田的仅约15英尺不等，但在那里仍形成了多产的油藏。单元。该成员被解释为沉积在新特提斯南部边缘的一个大型平台上，其中大布尔根地区占据了一个相对较近的区域。从岩心和薄层解释的沉积环境的范围从外到中，内和内平台，后者包括高能（浅滩和海岸线）和低能（泻湖）设置。碳酸盐岩层可分为两个低阶（可能是四阶）循环，上部循环的顶部对应于Mauddud组顶部的三阶层序边界。该边界代表了一个持久的暴露表面，其特征是不规则但突出的岩溶特征，包括空腔和高达米级的管道。在成岩作用修饰的早期和后期，碳酸盐岩中的大孔充满了方解石和亚铁白云石水泥。但是，由于成岩作用的成岩作用，该构件中部的微孔被保留并得到了增强，并且泥浆支撑，尽管渗透率<100 mD，但在该区间内占主导地位的内层平台碳酸盐岩的孔隙率高达〜35％。据推测，向碳酸盐岩成员油层中的石油赋存主要是在白云岩胶结之后发生的。

Kosakowski等人 的论文。pp。277–300上提供了新的有机地球化学数据，该数据是位于喀尔巴阡造山带北部和东北部的喀尔巴阡山脉前陆深部波兰中新世中部烃源岩的。始于1920年代的一系列相对较小的生物成因气田，在外部前深层中厚的中新世“糖蜜”演替中的砂岩形成了主要储层。在外部前缘的波兰地区发现了100多个气田，其中有85个正在生产。最大的Przemysl估计可采气储量为70 B m ³。前外部深部的糖蜜层序还包含有机质丰富的泥岩层段（巴登期-下萨尔马提期），具有烃源岩的潜力。在本文中，这些泥岩的岩心样品（n = 671）是从外部前深部的波兰部门的45个钻孔中回收的，并进行了标准的有机地球化学分析，包括岩石评估和生物标志物分析的GC / GC-MS。源岩的成熟历史是在9口井的1D模式中建模的。结果与以前发布的数据集成在一起。结果表明，总体而言，所分析的中新世中期样品的TOC含量适中（总体平均水平：约0.7％），且主要含有陆源III型干酪根和次要II型干酪根。样品在总体上不成熟，如Rock-Eval T _max（<430^o C）和生物标志物参数。模拟结果表明，烃源岩埋藏不足以产生热气，因此，据推测主要是由于生物成因在浅深度产生的。例如，由于喀尔巴阡山脉褶皱带的推覆作用，中新世中部烃源岩被埋藏到更深的地方可能会产生热气。

白垩纪早期的Lacustrine泥岩是大陆内走滑盆地和伸展盆地中的活跃烃源岩，构成了西非和中非裂谷系统（WCARS）。上白垩统和古近系演替中存在储层层段。然而，在邦戈尔盆地，乍得南部，这是通过在纸张的焦点窦丽绒等 。在第301-322页，一个与反转有关的隆升阶段可追溯到白垩纪至古近纪早期，这消除了其他WCARS盆地中存在的储层间隔。窦等。通过对石油样本和烃源岩的有机地球化学分析（包括GC和GC-MS数据）以及岩石学和其他储层单元研究，来表征邦戈盆地的石油生境。邦戈尔盆地的勘探始于1970年代，到2019年底，已经发现了约15个油气田，其中最大的油田（大猴面包树，于2009年发现）估计就地储量为1.5 B brl石油。石油是由前寒武纪晶体基底中的储层和下白垩统同生代相中的长石质砂岩中产生的。在地层学上，储层砂岩都发生在下白垩纪含羞草和上Prosopis地层中富含有机质的页岩烃源岩的下方和上方，其厚度达数百米或以上。_o 0.6–1.2％）。含羞草和Prosopis组页岩也形成了油气的有效区域性封存。这些成熟的烃源岩可作为非常规页岩油和某些地方的页岩气的储层。

Galushkin等 。（第323–340页）介绍了由两部分组成的数值模型研究的第一部分，该研究对西南澳大利亚和南极洲的研究不充分的共轭边距。在西北侏罗纪至白垩纪早期，北西向南至岩石圈南北延伸和裂谷的初始阶段发生在这里，土伦时期的澳大利亚和南极边缘发生了破裂。古近纪发生了伸展和海床迅速扩张的第二阶段。本文研究了澳大利亚西南海岸比特盆地布雷默盆地的沉降和热史。第2部分将考虑南极东部共轭边缘的莫森海盆地。对于两篇论文，Galushkin等。使用了GALO数值建模程序，该程序模拟了地壳，下层岩石圈和软流圈中的热传递，深度达100 km，并随时间对构造沉降进行了建模。从而确定并定量了岩石圈伸展相和热流的相位。论文的输入数据来自不来梅子盆地的一口伪井，该地层先前已建立地层。在此确定的六个地震地层单元的范围从上侏罗统到上白垩统，被称为不来梅1到不来梅6单元。重建了伪井位置的沉降和热历史，并模拟了潜在烃源岩的成熟历史。成熟度模型表明，在沉积裂谷底部的布雷默1单元中的同生河流相-湖相泥岩在裂谷的初始阶段就已经热成熟，可用于生烃，目前已经过熟。上覆的布雷默2、3和4单元中潜在烃源岩的成熟发生在自42 Ma以来的构造驱动沉降的第二阶段，产生了轻油和重油，其中一些可能已经裂化为天然气。

伊朗西南部Dezful Embayment的多产油田的石油系统由于过去数十年的详细研究而广为人知。因此，认为Albian Kazhdumi组和古近纪Pabdeh组的烃源岩可以为上白垩统Sarvak组和渐新世-中新世Asmari组提供储层。Vatandoust等人的论文 。341-358页的文章研究了位于Emavenment南部简单反斜构造中三个油田的阿斯马里组的装药历史。为了进行研究，从七口井中收集了阿斯马里组的岩心样品，并准备了双抛光薄层。然后仔细研究了Asmari碳酸盐中的流体夹杂物，包括在紫外线和拉曼光谱下进行的研究，并对选定的油和水包裹体进行了微量热分析，并测量了均质温度（T _h）。然后将这些数据与研究区域的埋葬历史进行整合，如先前的调查中所述。含油夹杂物的荧光颜色从黄绿色到蓝白色不等，表明存在来自不同成熟度烃源岩的油。同样地，测量的T _ħ用于油和水溶液的值有明显的双峰分布，这表明至少有两个油电荷的存在。通过积分流体包裹体T _h，这些油充注的日期定为〜7.3至3.5 Ma和3.5至2 Ma测量与埋葬和成熟的历史。对研究区的Kazhdumi和Pabdeh烃源岩进行的建模表明，这两个地层都没有被埋藏到足够深的深度，以致不会产生天然气。因此，对含气流体包裹体中甲烷的观察可能表明已经发生了油气裂解，这可能主要是由于所研究结构的上新世晚期隆升造成的。