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Nanomaterials are materials that possess unique properties due to their high specific surface area and quantum effects. Nanomaterials have diverse applications in different fields including the petroleum and gas industry as additives. One of the classes of nanomaterials that currently have potential usage in the downstream, midstream, and upstream processes of the petroleum industry is nanoparticles (NPs). Among the upstream processes in the petroleum and gas industry is the drilling operations. It is popular that the most critical features that ensure the success of a drilling operation are the rheological and filtration loss characteristics of the drilling fluid. The current work deals with the synthesis of green uncoated and polymer-coated green magnetite nanoparticles (MNPs). The MNPs were characterized and assessed as rheology and filtration loss modifiers for water-based drilling fluids. The optimum formulation design of drilling fluids incorporated the MNPs for high-performance drilling fluids in terms of density, rheological, filtration loss, and sagging properties was identified. The effect of temperature (ambient − 80 °C), and aging time (6–248 h) on the investigated properties were evaluated. The results confirmed that optimum values for plastic viscosity, apparent viscosity, yield Point, gel strength (10sec), gel strength (10 min), mud thickness, and sag index were 13.77 cP, 69.69 cP, 89.87 lb/100ft2, 86.75 lb/100ft2, 128.38 lb/100ft2, ≤ 1 mm, and 0.511, respectively. Most of those values could be reached using an optimum formulation involving 0.92 % MNPs at ambient temperature. Increasing the temperature displays a decrease in the values while increasing the aging time displays an increase in the values. Drilling fluids with MNPs showed insignificant changes in the investigated properties with increasing temperature in particular those incorporated with polymer-coated MNPs compared to the water-based drilling fluids., SCOPUS: ar.j, info:eu-repo/semantics/published

Matrix acidizing has been developed in the petroleum industry for improving petroleum well productivity and minimizing near-wellbore damage. Mud acid (HF: HCl) has gained attractiveness in improving the porosity and permeability of reservoir formation. However, there are several challenges facing the use of mud acid, comprising its corrosive nature, high pH value, formation of precipitates, high reaction rate and quick consumption. Therefore, different acids have been developed to solve these problems, including organic-HF or HCl acids. Some of these acid combinations proved their effectiveness in being alternatives to mud acid in reservoir rock acidizing. The current research deals with a new acid combination based on Hydrochloric–Oxalic acids for acidizing carbonate core samples recovered from Qamchuqa Formation in Kirkuk oilfield, northern Iraq. A new in-situ micro-model adopted laboratory technique is utilized to study the microscale alteration and evolution of pore spaces, dissolved grains and identification of matrix acidizing characteristics. The in-situ micro-model is based on the injection of an identical dose of different concentrations of the new acid combination into thin section samples under an optical light microscope. The adopted procedure aims to provide unique and rapid information regarding the potential for texture and porosity modification that can be caused by the acidizing stimulation procedure. In connection, solubility tests for the untreated and treated reservoir core samples and the density of the combined acids after treatment are conducted based on designed experiments using response surface methodology (RSM). The effect of acid concentration [12% HCl: Oxalic acid (3.8–8.8%)] and acidizing temperature (from ambient to 78.8 °C) on the solubility percentage of the samples and percentage increase in the combined acid density after acidizing were optimized and modeled. The obtained results confirm that the optimum dissolution of the core sam, SCOPUS: ar.j, info:eu-repo/semantics/published

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 produce, SCOPUS: ar.j, info:eu-repo/semantics/published

Drilling fluids are one of the most significant components of drilling operations for proper functions including fluid loss reduction into the formation and outstanding rheological properties. The drilling fluids according to environmental regulations and governmental rules have to be friendly to the environment to lessen the negative effects on the environment and improve safety. In the current study, a cost-effective industrial alkali waste (spent caustic) was used as a pH controller along with the environmentally friendly uncoated and Chitosan-coated green magnetite nanoparticles (MNPs) in water-based drilling fluid systems. The study focuses on exploring the impact of the alkali waste compared to the conventional alkali (NaOH) on rheology and filtration loss properties. The flow models of the drilling fluid systems were examined. The results proved that the drilling fluid formulated with polymer-coated green MNPs and waste alkali exhibited higher rheological properties and lower mud cake thickness and filtration volume compared to the reference fluid, thus, the waste alkali could replace NaOH as a pH controller. The flow behavior of new fluids could be described precisely using the Herschel-Bulkley flow model. Whereas, the Bingham plastic flow model described the fluid systems incorporated with uncoated and polymer-coated green NPs and NaOH., SCOPUS: cp.p, info:eu-repo/semantics/published

Oil production from depleted reservoirs in EOR (Enhanced Oil Recovery) techniques has significantly increased due to its huge demands in industrial energy sectors. Chemical EOR is one of the best approaches to extract the trapped oil. However, there are gaps to be addressed and studied well for quality and cost consideration in EOR techniques. Therefore, this paper addresses for the first time a systematic overview from alkaline surfactant polymer ((ASP)) and future perspectives of nano-alkaline surfactant polymer ((NASP)), its synergy effects on oil recovery improvement, and the main screening criteria for these chemicals. The previous findings have demonstrated that the optimum salinity, choosing the best concentration, using effective nano-surfactant, polymer and alkaline type, is guaranteed an ultra-low IFT (Interfacial Tension). Core flood results proved that the maximum oil is recovered by conjugating nanoparticles with conventional chemical EOR methods (surfactant, alkaline and polymer). This work adds a new insight and suggests new recommendation into the EOR application since, for the first time, it explores the role and effect of nanotechnology in a hybrid with ASP. The study illustrates detailed experimental design of using NASP and presents an optimum micro-model setup for future design of NASP flow distribution in the porous media. The presence of nano along with other chemicals increases the capillary number as well as the stability of chemicals in the solution and strengthens the effective mechanisms on the EOR., SCOPUS: re.j, info:eu-repo/semantics/published

A field, petrographic and geochemical study of two Triassic–Jurassic carbonate successions from the Maritime Alps, SE France, indicates that dolomitization is related to episodic fracturing and the flow of hydrothermal fluids. The mechanism governing hydrothermal fluids has been documented with the best possible spatio-temporal resolutions specifying the migration and trapping of hydrothermal fluids as a function of depth. This is rarely reported in the literature, as it requires a very wide range of disciplines from facies analysis (petrography) to very diverse and advanced chemical methods (elemental analysis, isotope geochemistry, microthermometry). In most cases, our different recognized diagenetic phases were mechanically separated on a centimetric scale and analyzed separately. The wide range of the δ18 OVPDB and87Sr/86Sr values of diagenetic carbonates reflect three main diagenetic realms, including: (1) the formation of replacive dolomites (Type I) in the eogenetic realm, (2) formation of coarse to very coarse crystalline saddle dolomites (Types II and Type III) in the shallow to deep burial mesogenetic realm, respectively, and (3) telogenetic formation of a late calcite cement (C1) in the telogenetic realm due to the uplift incursion of meteoric waters. The Triassic dolomites show a lower87 Sr/86Sr ratio (mean = 0.709125) compared to the Jurassic dolomites (mean = 0.710065). The Jurassic calcite (C1J) shows lower Sr isotopic ratios than the Triassic C1T calcite. These are probably linked to the pulses of the seafloor’s hydrothermal activity and to an increase in the continental riverine input during Late Cretaceous and Early Cenozoic times. This study adds a new insight into the burial diagenetic conditions during multiple hydrothermal flow events., SCOPUS: ar.j, info:eu-repo/semantics/published

Hydrothermal diagenesis during the Zagros Orogeny produced three phases of saddle dolomites (SD1, SD2, and SD3) and two phases of blocky calcites (CI and CII) in the studied sections of Bekhme Formation (Fm) (Campanian–Maastrichtian). Field observations, as well as petrographic, cathodoluminescence (CL), Scanning Elecron Microscope (SEM), and oxygen–carbon isotope analyses, indicated that the unit went through multiple submergence–emergence phases after or during hydrothermal diagenesis. These phases resulted in a characteristic calcretized 2–6-m-thick layer within the Bekhme Fm. Several pedogenic textures (e.g. alveolar, pisolite, and laminar fabric microfeatures) were observed. Strong evidence of microbial alteration and diagenesis in this formation brings new insights into its depositional history. The microbial activities developed on the original mineral surface were associated with a great variety of processes including dissolution, re-precipitation, replacement, open-space fillings, microporosity development, grain bridging, and micritization. Probable oxalate pseudomorphs embedded in these fabrics and regular filaments preserved along crystal boundaries suggest the activity of fungi, while frequent coccoidal, rod-like, and chain-like forms attached to the surfaces of dolomitic and calcitic crystals point to bacterial colonization. Extracellular polymeric substance (EPS) was often visible with fungal and bacterial forms. These features, together with stable isotope data, invoke that near-surface conditions occurred sporadically in the Bekhme Fm after the first generation of hydrothermal dolomitization. These new findings allow recognition of unreported sedimentological phases based on new evidence in the Spelek–Sulauk area during the Upper Cretaceous., SCOPUS: ar.j, info:eu-repo/semantics/published

Triassic-Jurassic outcrops in Provençal Domain-SE France and Upper Cretaceous Bekhme Formation in Harir-Safin anticlines-NE Iraq are extensively fractured and dolomitized along open spaces in carbonate rocks. Extensive fieldwork, enhanced petrography and geochemistry (trace, REE, major elements, 87Sr/86Sr, δ18OVPDB, δ13CVPDB), and U-Pb datings demonstrate the multi-phase generation of saddle dolomites and blocky calcites formed by the action of deep hot brine fluids, which migrated along fault zones.Petrography and geochemistry revealed three main diagenetic stages in the French Triassic (T)-Jurassic (J) studied outcrops. The first stage is characterized by crystalline replacive dolomites (D1T/ DJ) and medium-sized dolospars (D2T) precipitated in the eogenetic realm from normal seawater and meteoric fluids. The second stage with medium- to coarse-grained saddle dolomites (SD1T/J and SD2T/J) formed under shallow diagenetic realm during Early Cretaceous times, and very coarse-sized zoned and unzoned saddle dolomites (SD3T/J, SD4T/J, and SD5J, SD6J, DrJ) precipitated under deep diagenetic realm (Th between 120 °C and 278 °C) during a Late Cretaceous tectonic activity. Two types of stylolites, extensive fracturing of the carbonates, and breccia/zebra structures, were also formed as a result of the activities of two recognized sub-generations of hydrothermal fluid influxes associated to the second stages. Therefore, they are characterized by a pervasive polyphasic hydrothermal dolomitization that occurred along fractured zones with a wide range of δ18OVPDB and 87Sr/86Sr values. The transition from high (Th between 81 °C and 278 °C; av. = 207 °C) to low (Th between 44 °C and 77 °C; av. = 61 °C) fluid temperatures identifies the third stage of diagenesis. This stage produced the late calcitic cements C1T and C1J with extra-negative oxygen and carbon isotope compositions, and this is related to two different fluids during the uplifting of the studied area in Late Cretaceous, Doctorat en Sciences, info:eu-repo/semantics/nonPublished