Journal of Petroleum Geology最新文献

The drill bit is a crucial device in oil companies, and it is quite expensive. Therefore, studying its mechanical behavior is essential for preserving this device and reducing its maintenance costs. The drilling mud is among the practical things that influence the bit's performance during the drilling operation. This article presents a numerical study of mud rheology in Algerian oil and gas wells using computational fluid dynamics (CFD) analysis. This study aims to optimize the rheological and dynamic properties around the polycrystalline diamond compact (PDC) drill bit of 244 mm diameter in the Algerian borehole. The drilling mud used is a mixture of water, 0.15% of hydroxyethyl cellulose (HEC), and an Algerian bentonite base. The Herschel–Bulkley model has been used to characterize the rheological behavior of this drilling mud because it is a non-Newtonian fluid. The three-dimensional (3D) model of the PDC drill bit was meticulously designed using SolidWorks (version 24, 2016). Additionally, the dynamic behavior of the PDC drill bit in the presence of drilling mud was modeled and simulated using ANSYS Fluent software (version 19.0, 2018). The results indicate that although mud density has minimal impact on annular velocity, it significantly affects the pressure drop across the drill bit. In contrast, the drill bit's rotational speed directly influences annular velocity, which plays a critical role in mitigating stick–slip phenomena. This mitigation is achieved through the enhancement of cuttings transport from the bottom hole to the surface, thereby preventing accumulation around the drill bit, a primary contributor to stick–slip vibrations. These findings support previous studies that have established the influence of mud density on pressure drop and the critical role of rotational speed in mitigating stick–slip phenomena. The numerical results for fluid parameters at the nozzle, obtained using ANSYS Fluent, were validated against established oilfield empirical correlations, demonstrating satisfactory agreement.

The deposition of the Menilite Beds began during the reorganization of the sea ways and the extensional stage of the Carpathian Basin evolution in the early Oligocene. The beginning of their sedimentation is considered to be isochronous throughout the entire marine basin, which formed a part of the Paratethys and was likely isolated from the global ocean due to tectonic movements. However, the changes in the Carpathian region were likely also influenced by processes associated with the Eocene–Oligocene Transition. The present study focuses on the investigation of the Menilite Beds from two Outer Carpathians (OC) main tectonic units: the Skole (Krościenko section) and Silesian (Korzenna section), using a coupled palynofacies, Rock-Eval pyrolysis, and sedimentological framework. This approach permitted the observation of lateral variations in lithology, sedimentary structures, and palynofacies, recording the changes that took place in the early Oligocene, during the deposition of the Menilite Beds, in regions that are currently separated by great distances. In both sections, the palynofacies of the Menilite Beds are predominantly composed of amorphous organic matter (AOM), suggesting that the Menilite Beds were deposited under strongly oxygen-depleted conditions. The presence of spherical bacteria and AOM with alveolar structures in the Korzenna section indicates that microbial mats were probably locally present at the sediment–water interface during the deposition of the Menilite Beds. Analyses of microplankton with organic walls indicate that brackish conditions were present during the deposition of the lower Menilite Beds. Identified microplankton notably included Botryococcus sp. (Krościenko, Korzenna), Campenia sp. (Krościenko, Korzenna), Leiosphaeridia sp. (Krościenko, Korzenna), Pterospermella sp. (Krościenko, Korzenna), and Cymatiosphaera sp. (Korzenna). These results indicate that some lower Menilite Beds, which are located directly above the Eocene deposits (Krościenko—Complex II, III, and IV; Korzenna—Complex I, II, IV, VI), contain horizons with palynological compositions favorable to hydrocarbon generation, including Botryococcus sp. and Leiosphaeridia sp., which are characterized by a high ability to synthesize and accumulate hydrocarbon. We demonstrate that the integration of sedimentological, palynofacies, and organic matter analyses under UV light supported by Rock-Eval pyrolysis can facilitate the identification of potential hydrocarbon horizons—characterized by elevated algal abundances—within the differentiated lithostratigraphic profile of the Menilite Beds. The formation of these deposits was influenced by a complex interplay of paleogeographical, paleoclimatic, and tectonic factors.

The hydrocarbon migration conduits in the Outer Carpathian fold-and-thrust belt (OCFTB) are related to the dynamic development of the structural framework combined with changes of rock properties during the deformation process. Application of an integrated methodology, including fieldwork coupled with analysis of cores and thin sections as well as geophysical and petrophysical data from eight wells, made it possible to describe the relationships between the structural framework and the porous sandy rocks of the Cretaceous-to-Oligocene succession during the evolution of the OCFTB. The results indicate that the folding and thrusting, along with the associated rock fracturing during sustained horizontal contraction, resulted in the complex structure of the Silesian Nappe (part of the OCFTB). Structural deformation of lithified rocks created a system of conduits for hydrocarbon migration. The presence of bitumen in the thrust fault zones, normal faults and longitudinal joints (L), parallel to the anticline axes, transversal joints (T) and shear joints (D₁ and D₂) indicates permanent hydrocarbon migration through complex conduits formed by the subsequent structural deformation of the Silesian Nappe. The assembled evidence points to the existence of an interconnected system of a structural framework combined with porous carrier beds contributing to the formation of conduits for hydrocarbon migration during the progressive deformation of the OCFTB.

The HC-producing Putumayo Basin is located in Southwestern Colombia, forming the northern part of the Ecuadorian Oriente Basin. Traditional reservoirs are sandstones of the Caballos Fm. (Aptian–Albian) and also the ‘U and M2 Sandstones’ of the Villeta Fm. (Late Albian–Maastrichtian). To provide a frame for our observations, a review of the main tectosedimentary aspects and petroleum systems considered in the literature was carried out. To evaluate the potential of the carbonate layers as reservoirs, in addition to the traditional ones, a microtectonic study was carried out on some available carbonate-bearing cores from wells drilled in the Villeta Fm. Although not properly oriented in space when acquired, when available, dipmeter logs have contributed to the approximate 3D positioning of these cores. The recognized microstructures belong to two main tectonic events progressively superimposed in time from Upper Cretaceous to Recent and in space from West to East: (i) early features due to vertical compaction by overburden following deposition that develop gently deformed stratification and lamination surfaces around more competent objects generated by differential compaction, steep-angle normal faulting in competent levels with slickensides, subhorizontal stylolites and subvertical calcite veins with cuneiform patterns; (ii) later features due to ENE–WSW subhorizontal convergence by the action of the post-Eocene Andean convergence producing dextral transpressional reactivations on the pre-existing N–S normal faulting. The early compaction is usually associated with the onset of HC maturation and subsequent migration towards contemporaneous potential traps. The carbonate veins confirm that dissolution and precipitation processes have decreased the primary porosity and permeability of the reservoirs by calcareous cementation, especially in the deeper parts of the basin. If the Villeta Fm. is to be considered a potential unconventional or tight reservoir, the more efficient direction for future drilling is subhorizontal NNW–SSE. These studies on available cores are only complementary to the usual, more thorough and expensive methodologies of petrophysical reservoir analysis and mainly aspire to extract additional information considering the high costs of obtaining them.

The Anambra and the Niger Delta Basins are well-known hydrocarbon-producing sedimentary basins in Southern Nigeria. In the present research, bulk geochemical analysis, which includes total organic carbon (TOC) and rock pyrolysis, molecular markers, and bulk and compound-specific carbon isotopes (CSIAs), in addition to organic petrological analysis was carried out on source rocks of Cretaceous age from the Anambra Basin and oils (both Anambra and Niger Delta Basins) in order to provide information on why there was a sudden seizure in liquid hydrocarbon production in the ANAR oilfield of the Anambra Basin and also to shed more light on the unending debate on the source of Cretaceous Niger Delta oils. From the results, bulk geochemical data and maceral abundances revealed that Nkporo shales from well-x and outcrop Mamu shales are dominantly of Types II and III organic matters and are capable of producing oil and gas upon attaining appropriate thermal maturity, whereas outcrop Mamu coals are of Types II and II/III organic matter, with good potential for oil generation but with minor gas, especially in the deeper section of the basin. Organic matter richness as deduced from TOC revealed that the Mamu coals are the richest (average TOC: 50.74 wt%), whereas Mamu shales are richer (average TOC: 2.89 wt%) than Nkporo shales (average TOC: 1.66 wt%). The hydrocarbon generative potentials of the analyzed source rocks as obtained through the hydrogen index are highest in the Mamu coals (average: 329.25 mg HC/g TOC), and are followed by Mamu shales (average: 130.89 mg HC/g TOC), whereas the least was obtained in Nkporo shales (average: 69.73 mg HC/g TOC). The maximum temperature (T_max) and the vitrinite/huminite reflectance values of the source rocks are 396–443°C, 417–430°C, and 417–421°C, and 0.38%–1.51%, 0.23%–0.42%, and 0.22%–0.46% in Nkporo shales, Mamu shales, and coals, respectively. The values revealed that Nkporo shales are in immature to early–late hydrocarbon generation stages, whereas Mamu shales and coals are dominantly thermally immature. Further, the analyzed source rocks were deposited under sub-oxic-to-oxic conditions based on molecular indices and petrographic evidence. In the Nkporo shales, there was dominant input from lacustrine organic matter, as evident from the high abundance of C₂₈R sterane, higher C₂₁TT, and n-alkane maxima at n-C₂₀ and n-C₂₃. In contrast, the Mamu shales and coals and crude oil from the Anambra Basin received major input from terrigenous organic matter (high C₂₉ R sterane, C₂₉/C₂₇ ratios, wax index, terrigenous/aquatic ratio (TAR), C₁₉ + ₂₀TT, and n-alkane maxima at n-C₂₇–n-C₂₉). The oils (crude oils and condensates) from the Niger Delta are dominated by C₂₉ R steranes, whereas C₂₇ and C