Hasil untuk "Petrology"

E. S. Hills

Hamed Nejati, Ehsan Khamehchi, Ali Ashraf Derakhshan et al.

Abstract In loose sandstone reservoirs, sand enters the wellbore along with the production fluid. Sand production causes numerous problems, such as the erosion of downhole, wellhead, and surface equipment, ultimately leading to a decline in production. In this paper, the authors present a new epoxy-based nanofluid for controlling sand production. To demonstrate its effectiveness, a near-wellbore laboratory simulator system (NeWSS) was developed, which takes into account all downhole conditions, such as the radial distribution of flow, temperature, and reservoir pressure. The epoxy/g-C3N4-NS nanofluid has two special properties. First, carbon nitride nanosheets were used as an active strengthening agent to increase the compressive strength of the epoxy resin after curing. Second, a bubbling agent was used to create micro- and macro-pores, facilitating the movement of the production fluid and ultimately increasing permeability. Laboratory results showed that the optimum concentrations of the bubbling agent and g-C3N4-NS are 3 wt% and 0.5 wt%, respectively. The preflush solution (3% KCl, 3% surface modifier, and 5% organic solvent) used to remove formation fluids (oil and brine) before nanofluid sand consolidation resulted in good adhesion of the nanofluid to the sand matrix and significantly increased the compressive strength of the porous area. Results from the near-wellbore laboratory simulation system under reservoir conditions (90 °C and 2800 psig) show that the regained permeability is above 90% when the epoxy/g-C3N4-NS nanofluid is used along with preflush and overflush solutions. Moreover, the presence of the optimum concentration of g-C3N4-NS in the epoxy-based nanofluid increased the failure stress of the hollow cylinder sample by 0.7 MPa.

Taping He, Wenju Wang, Xiaobin Xie et al.

Abstract The sedimentary mechanisms and depositional processes of deep-water gravity flows in lacustrine basins remain incompletely understood, posing challenges for accurate reservoir prediction in continental rift basins. This study investigates the Triassic Yanchang Formation in the Ordos Basin to elucidate the genetic processes and evolutionary mechanisms of deep-lake gravity flow deposits. Through systematic core observations, grain size analysis (including mean size, sorting, skewness and kurtosis), and sedimentary facies analysis, we identified four distinct gravity flow types: (1) sandy debris flows, (2) muddy debris flows, (3) turbidity currents, and (4) slumps. Quantitative grain size parameters reveal significant differences among these facies, with mean grain size ranging from 1.19Φ to 3.53Φ. Three primary triggering mechanisms are recognized: seismic events (seismites), volcanic events (tuffaceous layers), and anoxic events ("Zhangjiatan" shales), with seismic and volcanic events exerting particularly strong influences. A new depositional pattern is proposed, detailing the complete evolutionary sequence from slope failure initiation to final deposition, encompassing the sliding-slumping-debris flow-turbidity current transition. This study advances understanding by: (1) establishing quantitative discriminators for different gravity flow types, (2) clarifying the causal relationships between external triggers and flow deposition, and (3) providing a comprehensive evolutionary framework for lacustrine gravity flow systems. These findings significantly enhance the ability to predict deep-lacustrine sedimentary architectures and hydrocarbon reservoirs, offering valuable insights for exploration in analogous rift basins.

F. J. Turner, J. Verhoogen

Michal Šujan, Kishan Aherwar, Rastislav Vojtko et al.

The data included in this article specify the characteristics of the Upper Miocene fill of the Turiec Basin and served for reconstruction of temporal evolution of depositional systems in this intermontane basin located within the Western Carpathians (Central Europe). The borehole lithological log data were used to describe the stratigraphy of the Turiec Basin in geological sections and were gained in the Geofond archive of the State Geological Institute of Dionýz Štúr. The sedimentological data were acquired by field research applying facies analysis to nine outcrop sites. The outcrops served for grain size analyzes performed by sieving and laser diffraction, for geochemical analyzes using ICP-ES, ICP-MS and XRF, and for mineralogical analyzes of whole rock and clay fraction by XRD. Moreover, the muddy layers on outcrops served for collection of 31 samples for the authigenic 10Be/9Be dating. The geochronological data are presented by using five different initial ratios for calculation, determined within the Turiec Basin at the Late Pleistocene alluvial fan and river terrace sites as well as at two Holocene muddy floodplain sites. Another initial ratio data are gained from an Upper Miocene lacustrine succession dated independently by magnetostratigraphy in previous research. Finally, a summary of previously published strontium isotope data from the Turiec Basin is included. The interpretations of the data are provided in Šujan et al., (2023) Palaeogeography, Palaeoclimatology, Palaeoecology 628, 111746.

Jalal M. Ahammad, Mohammad Azizur Rahman, Stephen D. Butt et al.

Abstract The occurrence of fluid flow near a wellhead is the major concern of the petroleum industry, as pressure drop, loss of formation, and other variables of interest are mostly affected in this region. The fluid flows from the hydrocarbon reservoir to the wellbore can be characterized as laminar to turbulent; thus, it is important to model this phenomenon with the integrated wellbore-reservoir model. Using 3D Navier–Stokes equations, an integrated wellbore-reservoir model is created in this study, and it incorporates the formation damage zone. For the porous-porous and porous-fluid interfaces, the General Grid Interface (GGI) approach is applied in conjunction with the conservative mass flux interface model. Model equations are solved using a velocity-pressure coupling solver that is pressure-based. For reliable and quick results, the system of equations is solved using an algebraic multigrid approach. The pressure diffusivity equation’s analytical solution under steady-state flow circumstances is used to validate the model. The integrated wellbore-reservoir model is applied to different reservoir scenarios, for example, different production rates, formation zones, and reservoir formation conditions. The results indicate that the present Computational Fluid Dynamics (CFD) model can be extended to simulate the real field scale model. integrated wellbore-reservoir modeling based on 3D Navier–Stokes equations with efficient computational techniques can lead the field of petroleum industries to advance current knowledge.

Bowen Shi, Jiajun Hong, Zhihua Wang et al.

Abstract As deep gas-condensate reservoirs are explored, the problem of paraffin deposition is becoming more prominent. Therefore, this paper collects condensate samples from representative paraffin deposition gas-condensate wells and analyzes basic physical properties. The cold plate deposition device is employed to study paraffin deposition behavior under well conditions and to divide the critical regions for paraffin deposition in gas-condensate wells. The experimental apparatus, such as the crude oil dynamic paraffin deposition rate tester, is utilized to investigate the preventive effect of paraffin dispersants and paraffin crystal modifier. The results show that there is significant phase change behavior in gas-condensate wells and gas phase is dominant form, but there is also phase evolution. It can be identified from the experiments that paraffin deposition is mainly located in the 1000 ~ 1500 m region, and a paraffin deposition identification chart has been established. The maximum deposition rate could reach 15.50 mm/year, which matched the temperature and pressure conditions of 45 ℃ and 70 MPa. The preventive effect of paraffin crystal modifiers greatly exceeds that of paraffin dispersants, with paraffin prevention rates of 85–95% at the optimal concentrations of 0.25–0.50 wt.%. The dissolving paraffin rate can reach 0.0169 g/min. It decreases the paraffin appearance temperature approximately 40% and significantly changes the paraffin crystal morphology. Increased deposition surface area of the cold plate structural design describes the paraffin deposition. This diagram facilitates the reliable identification of paraffin deposition areas and the deposition rates in the wellbore during production. The optimum amounts of BZ and PI paraffin inhibitors are quantified. This study provides a comprehensive understanding of the paraffin deposition behavior, and scientific basis and guidance for the selection of paraffin inhibitors in gas-condensate wells.

Xinyu Mao, Nianyin Li, Fei Chen et al.

Abstract In situ heat systems are a technology that effectively solves paraffin deposition and improves oil recovery. Generally, the oxidation–reduction reaction of sodium nitrite and ammonium chloride generates a large amount of heat to promote the melting of paraffin. An in situ heat system combined with an acid-resistant fracturing fluid system can form an in situ heat fracturing fluid system, which solves the problem of the poor reformation effect caused by cold damage during the fracturing process of low-pressure and high-pour-point oil reservoirs. In this paper, with the goals of system heating up to 50 °C, a low H+ concentration, a high exotherm, and reduction of the toxic and harmful by-product NOX, the preferred in situ heat system was found to comprise 1.6 mol/L ammonium chloride, 1.0 mol/L sodium nitrite, and 0.8% hydrochloric acid. The effect of five factors on the heat production of the reaction was studied experimentally, and a reaction kinetic equation for the in situ heat system was proposed based on the results. The results showed that increasing the concentration of the reactants and lowering the ambient temperature produced more heat. The in situ heat system was used to conduct a crude oil cold damage elimination experiment, and the results of the removal experiments verified that the system could effectively but not completely reduce the cold damage. Overall, the in situ heat fracturing fluid system formed by the preferred in situ heat system combined with an acid-resistant fracturing fluid system could avoid cold damage in the formation during construction and increase the output.

Fernanda Setta, Sérgio Bergamaschi, René Rodrigues et al.

Abstract This assessment of the volumetric potential of the oil shales of Tremembé Formation (Oligocene, Taubaté Basin, Brazil) was based on the sedimentological study of 2457 total organic carbon and 1007 Rock–Eval pyrolysis analyses of core samples from nine survey wells drilled in the central portion of Taubaté Basin. Along a 240-m-thick package in the upper part of Tremembé Formation, thirteen chemostratigraphic units with thicknesses varying from 10 to 35 m were identified. The upper interval (unit L), 30 m thick, exhibited the highest organic content and original generation potential and was thus studied in detail. In unit L, oil yield maps were constructed, seeking to identify the most attractive areas for industrially exploiting the oil shales, and volumetric calculations employing a probabilistic Monte Carlo method were conducted to quantify the potentially recoverable oil volume. Three exploratory scenarios based on yield values (S1 + S2) were considered for calculating the oil volumes, seeking to offer different exploratory scenarios for decision making. For the scenario that considered only average yields above 100 mg HC/g rock, the recoverable oil volume is 525 million bbl (P90) to 884 million bbl (P10); for the scenario that considered only average yields above 80 mg HC/g rock, the recoverable oil volume is 1.4 billion bbl (P90) to 2.6 billion bbl (P10); and for the scenario that considered only average yields above 60 mg HC/g rock, the recoverable oil volume is 3.6 billion bbl (P90) to 5.4 billion bbl (P10).

Alessandro Sandrin

Play analysis has been widely used in hydrocarbon exploration for decades with great success. In recent years, progress has also been made to describe reservoir properties of very low permeability reservoirs. However, comparatively little research has been conducted into play analysis for such reservoirs, which may lead to misleading estimates of their hydrocarbon potential. Here, the concept of a semi-conventional play is defined and characterised as having a reservoir of such low permeability that a hydrocarbon column can form down-dip of an effective dry trap. A new exploration approach is proposed for such plays using the Chalk Group Play in the Danish North Sea as an example. It is suggested that together with the usual risk elements, a more detailed analysis of ‘charge’ is necessary, paying particular attention to identifying possible hydrocarbon entry-points, palaeostructures and the maximum distance from these entry-points that the hydrocarbons may have reached since they first entered the reservoir. The application of this novel approach for semi-conventional plays in mature basins could help unlock further resources in proximity of existing fields, and reduce the risk of failure in frontier exploration.

Maryam Mohamadizadeh, Seyed Hossein Mojtahedzadeh, farimah Ayati

The Fertile pegmatites are known as the most important source of strategic and rare elements. These coarse-grained granitic units are related to potentially granitic intrusions and the identification of the parental intrusion is the first step of their exploration and recognition. In the present paper, the Moshirabad granite-pegmatite system located in southwest of Qorveh has been studied using bulk-rock data and available geological information in order to consider rare elements behavior and their contents. The investigations show that the studied igneous units did not formed in a unique fractionation succession, but rather happened separately in parallel differentiation processes. During sequential injections and development of fractionation (Rb increase and K/Rb decrease), the metals such as Sr, Zn, Ba, REEs, Th, Zr, and Hf were depleted whereas, the elements including Nb, Ta, Be, and Ga were enriched. In addition, the evidences imply that hydrothermal activities, also, involved in the concentration and depletion of the elements.

R. O. Lima, A. de L. Cunha, J. A. O. Santos et al.

Abstract Carbonate rocks have become very important in Brazil with pre-salt reservoir discoveries in Santos and Campos Basins. Since then, great efforts in research and technology have been made to characterize and develop these reservoirs. In this sense, outcrop analogue studies have become a powerful tool for helping the recognition of geological heterogeneities responsible for controlling the fluid flow in hydrocarbon reservoirs. Besides that, pre-salt oil recovery is associated with high carbon dioxide (CO2) production, and due environmental issues, it is required a sustainable destination for this contaminant. CO2 injection in the reservoir, either pure or mixed to the produced gas stream, could be a good manner to deal with this undesirable component and increase the oil recovery. This work uses outcrop analogue characterization to understand how carbonate reservoir characteristics impact the selection of the best recovery strategy under Brazilian-pre-salt-like conditions. Numerical simulation models were run using the flow simulator TEMPEST MORE (version 7.1) with isothermal compositional modeling. The oil recovery process was modeled by continuous and alternating injection of CO2 and water. The recovered oil fractions for the simulation case with water alternating CO2 injection were higher than with the use of continuous injection of CO2 or water.

Aniefiok Sylvester Akpan, Francisca Nneka Okeke, Daniel Nnaemeka Obiora et al.

Abstract 3D seismic volume and two well logs data labelled Bonna-6 and Bonna-8 were employed in the inversion process. The data set was simultaneously inverted to produce P- and S-impedances, density, V P  −  V S , and PI seismic attributes. An average “c” term value of 1.37 was obtained from the inverse of the slope of the crossplot of P-impedance versus S-impedance for Bonna-6 and Bonna-8 wells. This value was employed in the inversion process to generate the PI attribute, which aided in reducing the non-uniqueness inherent in discriminating the probable reservoir sands. Five seismic attributes slices were generated to ascertain the superiority of each attribute in delineating the probable reservoir sand. These attributes were: density, S-impedance, P-impedance, V P − V S ratio and PI. These attributes reveal low value of density (1.96 − 2.14 g/cc), P-impedance (1.8 × 104 − 2.1 × 104) ft/s*g/cc, S-impedance (9.2 × 103 − 1.1 × 104) ft/s*g/cc, V P  − V S (1.65 − 1.72) and PI (4.9 × 103 − 5.1 × 104) ft/s*g/cc around the area inferred to be hydrocarbon saturated reservoir. Although the attributes considered reveals the same zone suspected to be probable hydrocarbon zone, PI gives a better discrimination when compared to other attributes. A distinctive spread and demarcation of the delineated hydrocarbon sand are observed in the PI attribute slice.

J. Didier, B. Barbarin

J. Ita, L. Stixrude

Santosh Garain, Debashis Mitra, Pranab Das

Abstract Subsurface hydrocarbon traps are not correctly sealed, and hydrocarbons move vertically from the reservoir as invisible traces in the form of microseepages. Long-term hydrocarbon microseepages cause surface or near-surface alterations such as bleaching of red beds, enrichment of ferrous iron minerals and higher concentrations of clay and carbonate minerals in soils/rocks. Multi- and hyperspectral remote sensing data have successfully been used to detect such alterations in many parts of the world. In India, such studies have not been carried out till now. In this study, Landsat 7 ETM+ images have been used to find out hydrocarbon microseepage-bearing areas in part of Assam–Arakan Fold Belt in the northeastern part of India. Based on the spectral characteristics of the hydrocarbon microseepage-induced altered minerals, two spectral enhancement techniques, viz. principal component analysis (PCA) and band ratio analysis, have been carried out on the Landsat 7 ETM+ images. PCA reveals that three principal component images—1457PC3, 1345PC2 and 3457PC4—show relatively better enhancement for the hydrocarbon-bearing alteration areas. Again, band ratio analysis of the images indicates that ratio images—3/1, (2 + 5)/(3 + 4) and 7/5—show excellent spectral enhancement for the hydrocarbon-induced mineral alterations. The three PC images have been combined with the three band ratio images to find out probable hydrocarbon microseepage areas. The remote sensing-derived prospect areas have been validated with surface geochemical, seismic/geologic and gravity data available in the area.

Omid Mosalman Haghighi, Ali Mohsenatabar Firozjaii

Abstract Enhancing oil recovery from oil-wet carbonate oil reservoir is an important challenge in the world, especially in Middle East oil field. Surfactant and smart water can change the interfacial tension and wettability condition of this type of rock to water wet from oil wet. The present study follows the experimental work of the combination of new green surfactant with smart water to enhance oil recovery from a carbonate oil-wet rock. Wettability alternation and IFT reduction by surfactant, smart water and combination of surfactant with smart water were investigated experimentally. The results show that making surfactant solution using smart water can reduce oil saturation by reducing IFT and alter wettability conditions. The oil recovery factor at the end of water, surfactant and surfactant–smart water flooding was 36, 52 and 66%, respectively. It shows that combination of surfactant with smart water can help surfactant to be powerful.

Kazeem A. Lawal

Abstract Heat losses to cap and base rocks undermine the performance of a thermal flood. As a contribution to this subject, this paper investigates the applicability of the principles of heat exchanger to characterise heat losses between a petroleum reservoir and the adjacent geologic systems. The reservoir-boundary interface is conceptualised as a conductive wall through which the reservoir and adjacent formations exchange heat, but not mass. For a conduction-dominated process, the heat-transport equations are formulated and solved for both adiabatic and non-adiabatic conditions. Simulations performed on a field-scale example show that the rate of heating a petroleum reservoir is sensitive to the type of fluids saturating the adjoining geologic systems, as well as the characteristics of the cap and base rocks of the subject reservoir. Adiabatic and semi-infinite reservoir assumptions are found to be poor approximations for the examples presented. Validation of the proposed model against an existing model was satisfactory; however, remaining differences in performances are rationalised. Besides demonstrating the applicability of heat-exchanger theory to describe thermal losses in petroleum reservoirs, a novelty of this work is that it explicitly accounts for the effects of the reservoir-overburden and reservoir-underburden interfaces, as well as the characteristics of the fluid in the adjacent strata on reservoir heating. These and other findings should aid the design and management of thermal floods.

Neda Amirteymoori, Seyyed Saeid Mohammadi, Malihe Nakhaei

Volcanic rocks are observed in Ebrahim abad area, southwest of Gazik and in southern Khorasan province that located in northern part of the Sistan suture zone. The studied lavas consist of basaltic andesite, andesite and dacite with Eocene to Miocene age accompain pyroclastic rocks such as tuff. Main minerals in basaltic andesite include of plagioclase, pyroxene and olivine, in andesite consists of plagioclase, hornblende and pyroxene and in dacites composed of plagioclas, quartz and hornblende. Intermediate volcanic rocks have porphyritic with microlitic groundmass, megaporphyritic, glomeroporphyritic and poikilitic textures and common texture in dacite is porphyritic with microgranular groundmass. These rocks show disequilibrium evidences such as zoning in plagioclases, sieve texture and embayment in some minerals. Geochemical studies indicate that the lavas of Ebrahim abad area belong to calc alkaline series. These rocks have enrichment in LREE relative to HREE. The high value of LREE and large ion lithophile elements (LILE) relative to HFSE and negative anomaly in Nb and Ti, represent a subduction tectonic environment and active continental margin. The original magma of these lavas probably derived from partial melting of spinel- garnet lherzolite mantle that enriched by subducted slab fluids.

F. R. Boyd, Yingwei Fei, C. Bertka et al.