Namam Salih

يلعب تكوّبن نظام الكسور وتطور السوائل الجيولوجية في الظروف البيئية الضحلة والعميقة دورًا حاسمًا في مختلف العمليات الجيولوجية وتطبيقات البترول. تُقيّم هذا البحث البيانات الشاملة لتوفير فهم معمق لنظام الكسور المتعددة، الذي تملأه مراحل التماسك/الذوبان المختلفة المرتبطة بسوائل مختلفة قرب السطح وتحته. استخدمت هذه الدراسة مجهرًا ضوئيًا ورصدًا ميدانيًا مكثفًا لتتبع التكوين المستهدف ونظام الكسور اللاحقة في العصر الجوراسيك. حددت الدراسة خمسة أنواع رئيسية من الكسور: (1) FI الناتج عن ظروف سطحية أو قريبة من السطح، حيث بدأت تكوين الكسور ليس أحدث من توقيت ستيلوليت منخفض السعة. (2) الكسور FII المتشكل في دفن ضحل، وكان متزامنًا مع ستيلوليت منخفض السعة "الستيلولايت المبكر". (3) FIII الكسور المتشكل في ظروف تحت سطحية متزامنة مع ستيلوليت عالي السعة (4)الكسور الرابعة (FIV) المملوءة بأسمنت الكالسيت مع وجود كميات وفيرة من شوائب سائل البيتومين الصلب؛ و(5) الكسور الخامسة (FV) المملوءة بأسمنت الدولوميت. ترتبط خصائص ومظهر بلورات الدولوميت، والتآكل، والتلامس الخيطي بين حبيبات الدولوميت السرجي، والحبيبات المضغوطة بإحكام ارتباطًا مباشرًا...

This study utilizes high-resolution X-ray computed tomography (CT) to evaluate the reservoir characterization in heterogenous carbonate rocks. These rocks show a diagenetic alteration that influences the reservoir quality in the Cretaceous Qamchuqa–Bekhme formations in outcrop and subsurface sections (Gali-Bekhal, Bekhme, and Taq Taq oilfields, NE Iraq). The scanning of fifty-one directional line analyses was conducted on three facies: marine, early diagenetic (non-hydrothermal), and late diagenetic (hydrothermal dolomitization, or HTD). The facies were analyzed from thousands of micro-spot analyses (up to 5250) and computed tomographic numbers (CTNs) across vertical, horizontal, and inclined directions. The surface (outcrop) marine facies exhibited CTNs ranging from 2578 to 2982 Hounsfield Units (HUs) (Av. 2740 HU), with very low average porosity (1.20%) and permeability (0.14 mD) values, while subsurface marine facies showed lower CTNs (1446–2556 HU, Av. 2360 HU) and higher porosity (Av. 8.40%) and permeability (Av. 1.02 mD) compared to the surface samples. Subsurface marine facies revealed higher porosity, lower density, and considerably enhanced conditions for hydrocarbon storage. The CT measurements and petrophysical properties in early diagenesis highlight a considerable porous system in the surface compared to the one in subsurface settings, significantly controlling the quality of the reservoir storage. The late diagenetic scanning values coincide with a saddle dolomite formation formed under high temperature conditions and intensive rock–fluid interactions. These dolomites are related to a hot fluid and are associated with intensive fracturing, vuggy porosities, and zebra-like textures. These textures are more pronounced in the surface than the subsurface settings. A surface evaluation showed a wide CTN range, accompanied by an average porosity of up to 15.47% and permeability of 301.27 mD, while subsurface facies exhibited a significant depletion in the CTN (<500 HU), with an average porosity of about 14.05% and permeability of 91.56 mD. The petrophysical characteristics of the reservoir associated with late-HT dolomitization (subsurface setting) show two populations. The first one exhibited CTN values between 1931 and 2586 HU (Av. 2341 HU), with porosity ranging from 3.10 to 18.43% (Av. 8.84%) and permeability from 0.08 to 2.39 mD (Av. 0.31 mD). The second one recorded a considerable range of CTNs from 457 to 2446 HU (Av. 1823 HU), with porosity from 6.38 to 52.92% (Av. 20.97%) and permeability from 0.16 to 5462.62 mD (Av. 223.11 mD). High temperatures significantly altered the carbonate rock’s properties, with partial/complete occlusion of the porous vuggy and fractured networks, enhancing or reducing the reservoir quality and its storage. In summary, the variations in the CTN across both surface and subsurface facies provide new insight into reservoir heterogeneity and characterization, which is a fundamental factor for understanding the potential of hydrocarbon storage within various geological settings.

This study provides a detailed geochronological paragenesis of fracture systems from the Upper Jurassic petroleum source formation in NE Iraq, utilizing U-Pb dating, integrated with microprobe analyses and petrographic studies. Five fracturing stages are recognized (FI–FV), indicating significant tectonic and temperature changes from the Late Jurassic to Pliocene times (approximately 5.2–5.5 Ma). The burial history curve shows continuous subsidence events, starting with initial burial of the Barsarin Formation reaching depths of 1000–1200 m by 110 Ma, this depth interval coincides with the first fracturing stage (FI). The buffered system of FI by pristine facies and geometrical cross-cutting of FI with early stylolite formation show a prior formation of stylolite. Subsequent fracturing stages FII (28.6 ± 2 Ma, Oligocene) and FIII (19.83 ± 0.43 Ma, Early Miocene) were contemporaneous with tectonic deformation phases and hydrocarbon generation times. Microprobe and optical analyses demonstrate variations in mineralogical composition, particularly in FIV/FV-filled calcite and dolomite cements (12.2 ± 1.5 Ma and 5.5 Ma), highlighting the periods of conduit formation for the hydrocarbon migration. Backscattered electron (BSE) imaging reveals a textural alteration of these cements, especially those associated with fluorite precipitation, which further support the hydrothermal entrapment associated with the hydrocarbon migration. The hydrocarbon entrapment appeared in at least two episodes under subsurface setting under temperatures exceeding 100 °C. In summary, the significant meaningful ages and compositional analyses obtained from this study reveal crucial insights into the dynamics of fracture-filling cements and hydrocarbon entrapment mechanisms within the petroleum source rock formation. The novelty of these data would enhance our understanding of the complex relationship between structural geology and migration conduits, highlighting the influence of fracture-filling cements on hydrocarbon accumulation and reservoir quality as a main target for hydrocarbon field development.

The sequence of the Khurmala Formation located in northeastern Iraq was measured and sampled to evaluate its paleoenvironmental features, including sedimentological and microfacies analyses. The studied formation was analyzed under an optical microscope and was dominated by three main types of microfacies: coralligenous–algal wackestone, foraminiferal–peloidal packstone, and foraminiferal–peloidal grainstone. These hosted microfacies in the Khurmala Formation rarely contain a non-geniculate algae that insufficient for complete reef-building as a crest, but among the common algae, there are calcareous geniculate and green algae associated with benthic foraminifera and a minor component of planktonic foraminifera in the basin due to high-energetic open shallow-water environmental conditions during the deposition of the Khurmala Formation. The relative percentages of foraminifera, including both benthic and planktonic, plotted on triangular diagrams revealed a graphic indicator of paleoenvironment analyses. Detailed examination and analyses for microfacies, new findings of calcareous green algae (Acicularia and Clypeina), and microfacies analyses based on the triangle method and standard facies zones, denote that the upper part of the Khurmala Formation was richer in fined grain and Acicularia green algae, reflecting lower energy conditions than during deposition in the lower part of the formation, which was represented by algal wackestone microfacies and dominated by Clypeina green algae. In summary, these fluctuations in facies/microfacies changes, the appearance of new green algae, and different percentages of foraminiferal content are linked to the global sea level fluctuation that occurred during the Paleocene–Eocene interval.

Iron ore deposits have been identified from Nawgwezany Mishao in the Shalair Valley area within the Iraqi Zagros Suture Zone (IZSZ) at NE-Iraq. The iron ore is mainly hosted by the Shalair Metamorphic Rock Group calcschist. The transmitted and reflected light microscope study and X-ray diffraction of the calcschist revealed that the predominance minerals are calcite, and sillimanite, while muscovite, graphite, k-feldspar, and opaque mineral represent minor constituents. Meanwhile, skarn host rock as a second host rock shows the mineral assemblages of clinopyroxene, quartz, hornblende, epidote, plagioclase, sericite, garnet, and opaque minerals. The field and petrographical data indicated that the iron ore includes magnetite, hematite, pyrite, martite, goethite, and limonite. Magnetite and hematite constitute the predominant minerals of the ores, which display variable shape sizes (from < 1 cm to > 10 m) and chiefly occurred as massive, veins, veinlets, and disseminated grains. Based on some magnetite grains, filled veins in the host rocks support the hydrothermal ore-forming processes. The paragenetic sequence of iron ore and the presence of dendritic manganese texture on the surface of some of the skarn host rocks, as well as the petrographical identification of calcite twins in calcschist of types one and two, are the three reasons that point to the hydrothermal skarn origin of the iron ore. Overall field evidence, morphology, mineralogy, textures, calcite twins, and dendritic manganese texture on the surface of calcshist host rocks suggest that the Nawgwezany Mishao iron ore is related to the hydrothermal skarn deposit.

It is well recognized that PVT data are essential in oil and gas production facilities as well as in the determination of the reservoir fluid composition in reservoir engineering calculations. In the current work, the studied borehole is located in Tawke oilfield in the High Folded Zone. The structural geology and lithological facies of rocks are studied and found to comprise fine crystalline dolomite and anhydrite interbedded with claystone and dolomite. In addition, the practical PVT data of black oil from Tawke oilfield, Zakho, from reservoirs to transgressive–regressive cycles, are studied. The PVT data are investigated to derive the empirical models that rule and correlate the properties of the reservoir fluids in terms of the amount of natural gas (methane, ethane, and propane) dissolved in reservoir fluids and evolving from the wells. The characteristics of the reservoir fluid, including °API, viscosity at reservoir pressure and bubble-point pressure, reservoir pressure and temperature, gas–oil ratio (GOR), coefficient of compressibility at reservoir pressure, gross heating value, and sample depth, are correlated. The lithological part reveals that the carbonate and some clastic rock facies are conducive to enhancing natural gas adsorption. The reservoir fluid properties show adverse effects on the amount of natural gas constituents evolving from the wells, while it shows positive effects on the dissolved reservoir fluids. The estimated empirical correlations can help indicate the quantity of natural gas that is dissolved in reservoir fluids and liberated from the wells depending on the characteristics of the reservoir. In addition, they can be used in numerical simulators to predict oil well performance.

The X-ray computed tomography method has provided unrivalled data about the characterization and evolution of the internal/external structure of materials by analyzing CTN and non-destructive imaging approach. Applying this method on the appropriate drilling-fluid ingredients plays a significant role in generating proper mud cake quality to stabilize wellbore, and avoid formation damage and filtration loss by preventing drilling fluid invasion into the formation. In this study, smart-water drilling mud containing different concentrations of magnetite nanoparticles (MNPs) was used to assess the filtration loss properties and formation impairment. Conventional static filter press, non-destructive X-ray computed tomography (CT) scan images and high-resolution quantitative measurement of CT number method were used to estimate the filtrate volume and characterize the filter cake layers, hence evaluating the reservoir damage through hundreds of merged images. The CT scan data were combined with the HIPAX and Radiant viewer digital image processing. The variation in CT number of mud cake samples under different concentrations of MNPs and without MNPs concentration were analyzed, and hundreds of 3D images as a cross-sectional profile were used. This paper highlights the importance of MNPs property in terms of minimizing filtration volume and improving mud cake quality and thickness, and hence improving the wellbore stability. From the results, a notable reduction of filtrate drilling mud volume and mud cake thickness to 40.9% and 46.6%, respectively, were recorded for drilling fluids incorporated with 0.92 wt.% of MNPs. However, this study asserts that optimal MNPs should be implemented to guarantee the best filtration property. As confirmed from the results, increasing the MNPs concentration beyond the optimal value (up to 2 wt.%) increased the filtrate volume and mud cake thickness by 3.23 and 33.3%, respectively. CT scan profile images show two layers of mud cake produced from water-based drilling fluids possessing 0.92 wt.% MNPs. The latter concentration was found to be the optimal additive of MNPs as it caused a decrease in filtration volume, mud cake thickness, and pore spaces within the structure of the mud cake. Using the optimum MNPs, the CT number (CTN) shows a high CTN and density material, and uniform compacted thin mud cake structure (0.75 mm). The produced thin mud cake layer reveals the precipitation or exchange of elemental/mineral composition during fluid-solid interaction. These results confirm that MNPs could help in avoiding or reducing the formation damage, driving away drilling fluid from the formation, and improving borehole stability.