Oil Zone Research Articles

SUPLEMENTATION OF VIRGIN COCONUT OIL (VCO) PRODUCTS WITH INTARAN (Azadirachta indica) LEAF EXTRACT IN INHIBITING THE GROWTH OF ACNE BACTERIA Propianibacterium acnes

<p>The dangers of resistance to Propionibacterium acnes and the high cost of treatment prompted the discovery of medicinal sources from natural substances that could act as antibacterials. One of them is using post-harvest coconut products in the form of virgin coconut oil (VCO) with extract of intaran leaves (Azadirachta indica). The purpose of this study was to determine the phytochemical characteristics, inhibition zone and their categorization and to study the difference or effect of VCO supplemented with extracts of intaran leaves (Azadirachta indica) with various concentrations on the growth of Propionibacterium acnes. This study used a posttestonly control group design. The VCO mixed with extracts of intaran leaves with various concentrations of 5%, 10%, 15%, 20% and 25%. The antibacterial test was carried out using the Kirby-Bauer disc diffusion method. Data analysis used the Kruskall Wallis and Mann Whitney test. The VCO mixture supplemented with extracts of intaran leaves showed the presence of tannins, flavonoids, terpenoids, saponins, and alkaloids. The mean diameter of the inhibition zone of virgin coconut oil (VCO) supplemented with leaf extract at a concentration of 5%, 10%, 15%, 20% and 25% of the growth of P. acnes is 9.4 mm; 18.3 mm; 9.9 mm; 12.6 mm; and 9.9 mm. Data analysis showed that there were differences and the effect of adding extracts to the resulting inhibition zone diameter. The concentrations of leaf extract of 5%, 15%, and 25% were classified as moderate, while the concentrations of 10% and 20% of leaf extract were classified as strong. The 10% concentration had the highest inhibition zone diameter in inhibiting the growth of P. acnes. This combination has the potential to treat acne and needs to be carried out in vivo research.</p>

Microstructural wettability of oil and gas condensate zones of the Karachaganak field

The Karachaganak field is represented by gas condensate and oil zones, a convenient object for studying changes in microstructural wettability during the transition from one zone to another. Microstructural wettability was characterized by a hydrophobization coefficient, Ѳн, which determines the proportion of the pore surface area occupied by adsorbed hydrocarbons. It was found that Ѳн of the samples of the gas and gas condensate zones is the same (on average 0.140), the oil zone - on average 0.250. Analysis of the IR spectra of extracted hydrocarbons showed that the microstructural wettability of the oil zone contains more aromatic, aliphatic, oxidized and sulfur-containing structures and fewer branched structures than in the gas condensate zone. The microstructural wettability of carbonate reservoirs depends on the hydrocarbon composition of the adsorbed oil. Keywords: microstructural wettability; hydrophobic coefficient; hydrocarbons; spectral coefficients.

A method for determining fluids contact and identifying types of reservoir fluids in the F3-sandstone reservoir, field case study in Libya

This research study focuses on the use of tools for well X05-NC169a in (X field) in Libya. Tools such as reservoir saturation tool and repeat formation tool used in this study. F3-Sand Stone is the main reservoir and has a gross thickness ranging from 130 to 187 feet. The aim of this study is to identify the type of fluid and to determine fluid contacts in the F3 - Sand Stone Reservoir. The study was based on a petro-physical evaluation on the well X05-NC169a by using log data (Gamma Ray Log, Resistivity Log, Neutron Log and Density Log). The Techlog software was used to analyze the log data, while the Surfer software was used for mapping. The results indicate that it has a hydrocarbon and water column. Apart from combining the petro-physical results of well tests ( RFT data and RST) is to define the reservoir fluids type. The fluid contacts changed when the hydrocarbon fluid level decreased. The most dominant Hydrocarbon in the reservoir, according to RFT, RST, and Petro-physics data, is predominantly two phases. Zones of gas and oil.

Geological structure of Tomsk oil and gas promising zone: new data

Geological structure of Tomsk oil and gas promising zone: new data

Arctic Shelf Oil and Gas Prospects from Lower-Middle Paleozoic Sediments of the Timan–Pechora Oil and Gas Province Based on the Results of a Regional Study

The Timan–Pechora oil and gas province (TPP), despite the good geological and geophysical knowledge of its central and southern regions, remains poorly studied in the extreme northwestern part within the north of the Izhma–Pechora depression and the Malozemelsk–Kolguev monocline, and in the extreme northeast within the Predpaikhoisky depression. Assessing the oil and gas potential of the Lower Paleozoic part of the section is urgently required in the northwestern part of the TPP, the productivity of which has been proven at the border and in the more eastern regions of the province (Pechora–Kolva, Khoreyverskaya, Varandei–Adzva regions), that have been evaluated ambiguously. A comprehensive interpretation of the seismic exploration of regional works was carried out, with the wells significantly clarifying the structural basis and the boundaries of the distribution of the main seismic facies’ complexes. The capabilities of potentially oil- and gas-producing strata in the Silurian–Lower Devonian were studied. An analysis of migration routes in transit strata used for basin modeling in order to reconstruct the conditions of oil and gas formation that are common in the land and water areas of the Arctic zone of the TPP was carried out. Modeling allowed us to reach an understanding of the formation of large zones with possible accumulations of hydrocarbons, including the time at which the formation occurred and under what conditions, to establish space–time links with possible centers of generation to identify migration directions and, based on a comparison with periods of intensive generation of hydrocarbons both directly located within the work area and beyond (noting the possible migration), to identify zones of the paleoaccumulation of hydrocarbons. The body of existing literature on the subject made it possible to outline promising oil and gas accumulation zones, with the allocation of target objects for further exploration in the Lower Paleozoic part of the section.

Взаимообусловленность гидрохимических и гидродинамических процессов в эвапоритовых нефтегазоносных бассейнах

The article examines the reasons for the formation of vertical hydrochemical inversion within particular oil and gas basins and points out the role of waters of different genesis in the development of this phenomenon. The following processes of reverse hydrochemical zoning in the sedimentary cover are analyzed: thickening of heavy clay strata and the related squeezing of loosely bound waters, dehydration of clay minerals and catagenic fluid generation accompanying the transformation of organic matter into hydrocarbons of the petroleum series. The hydrochemical inversion at great depths is noted to occur and persist in the environment of the passive hydrodynamic regime; in closed water-drive systems, the demineralization of waters with depth causes the decrease in the hydrodynamic potential gradient, determining the migration pattern not only of water but also of hydrocarbons and, consequently, the location of oil and gas accumulation zones.

Strandings of sea turtles on beaches around the oil capital in Brazil

The south-western region of the Atlantic Ocean has feeding and nesting areas for the five species of sea turtles registered in Brazil, which are in different degrees of extinction threat, mainly due to anthropogenic factors. Fishing and the ingestion of solid waste, were identified as causing stranding and the mortality of sea turtles. In this work, data from the monitoring of beaches in the Municipalities of Macaé and Rio das Ostras, important oil zone in Brazil, in the north-central region of the State of Rio de Janeiro, were used in order to analyse the effects of seasonality on the sea turtle stranding. The monitoring was carried out daily from September 2017 to June 2019, in a study area covering 23.8 km long beach. Stranding data were obtained from active (n = 126) and passive (n = 66) monitoring of beaches and included the records of Chelonia mydas (n = 151), Caretta caretta (n = 23), Lepidochelys olivacea (n = 14), Dermochelys coriacea (n = 2) and Eretmochelys imbricata (n = 1). The largest stranding record occurred in the summer (n = 61) and spring (n = 60), a period compatible with the reproductive season of the species. The results obtained in this study emphasise the importance of the analysis of strandings of sea turtles, which provide relevant data on the biology of the group, the intra and interspecific dynamics and the state of conservation of these animals.

The benefits and dangers of using artificial intelligence in petrophysics

Artificial Intelligence, or AI, is a method of data analysis that learns from data, identify patterns and makes predictions with the minimal human intervention. AI is bringing many benefits to petrophysical evaluation. Using case studies, this paper describes several successful applications. The future of AI has even more potential. However, if used carelessly there are potentially grave consequences. A complex Middle East Carbonate field needed a bespoke shaly water saturation equation. AI was used to ‘evolve’ an ideal equation, together with field specific saturation and cementation exponents. One UKCS gas field had an ‘oil problem’. Here, AI was used to unlock the hidden fluid information in the NMR T1 and T2 spectra and successfully differentiate oil and gas zones in real time. A North Sea field with 30 wells had shear velocity data (Vs) in only 4 wells. Vs was required for reservoir modelling and well bore stability prediction. AI was used to predict Vs in all 30 wells. Incorporating high vertical resolution data, the Vs predictions were even better than the recorded logs. As it is not economic to take core data on every well, AI is used to discover the relationships between logs, core, litho-facies and permeability in multi-dimensional data space. As a consequence, all wells in a field were populated with these data to build a robust reservoir model. In addition, the AI predicted data upscaled correctly unlike many conventional techniques. AI gives impressive results when automatically log quality controlling (LQC) and repairing electrical logs for bad hole and sections of missing data. AI doesn’t require prior knowledge of the petrophysical response equations and is self-calibrating. There are no parameters to pick or cross-plots to make. There is very little user intervention and AI avoids the problem of ‘garbage in, garbage out’ (GIGO), by ignoring noise and outliers. AI programs work with an unlimited number of electrical logs, core and gas chromatography data; and don’t ‘fall-over’ if some of those inputs are missing. AI programs currently being developed include ones where their machine code evolves using similar rules used by life’s DNA code. These AI programs pose considerable dangers far beyond the oil industry as described in this paper. A ‘risk assessment’ is essential on all AI programs so that all hazards and risk factors, that could cause harm, are identified and mitigated.

Gas-hydrogeochemical conditions of the Bilche-Volytsia oil-gas-bearing area (Carpathian foredeep, Ukraine)

Introduction. Water-dissolved gases in exploratory oil and gas hydrogeology are the fundamental criteria of oil and gas potential. Their quantitative and qualitative characteristics allow to study the conditions of formation and preservation of the hydrocarbon deposits and to identify the perspective searching areas. The purpose of article was to determine the vertical and lateral gas-hydrogeochemical zonation of the Bilche-Volytsia oil and gas zone, to assess the role of water-dissolved gases in the formation of gas fields with the prospect of predicting new hydrocarbon deposits. The research methods base on the calculation and interpretation of the following parameters: gas saturation of water, saturation pressure, gas saturation coefficient. Graphs of dependences based on experimental studies from published scientific publications were used to determine the solubility of methane. The results of research. Nitrogen-methane composition of water-dissolved gases of the Upper Jurassic and Upper Cretaceous aquifers in combination with specific geochemical characteristics of groundwater of the north-western and central parts of the Bilche-Volytsia OGBA indicate the open hydrodynamic conditions, which, in general, are unfavourable for the formation and preservation of hydrocarbon deposits. In deep-submerged reservoirs of the south-eastern part of this area, water-dissolved gases of the Upper Jurassic and Upper Cretaceous aquifers are characterized by high contents of methane homologues. In the Upper Badenian aquifer the lateral distribution of water-dissolved methane is presented in the growth of its portions from the West and East European platforms in the direction of the sub-submerge of the Carpathians, which is due to an increase in the degree of hydrogeological closure of structures. Increased methane contents also spatially tend to transverse tectonic faults, which determines their role in the vertical migration of water-hydrocarbon mixtures. Water-dissolved gases of the highly productive Lower Sarmatian aquifer are mainly methane, occasionally nitrogen-methane. The gas saturation of the waters directly correlates with the proximity to gas deposits. Laterally, the portion of water-dissolved methane is directly correlated with TDS of water, the high values of which accordingly reflect the structures of a high degree of hydrogeological stagnation. Conclusions. The portions of water-dissolved methane increase from the West and East European platforms in the direction of the sub-submerge of the Carpathians, which is effect of higher degree of hydrogeological closure of structures. It has been established that water-dissolved methane, nitrogen and carbon dioxide have different sources of origin and different spatiotemporal mechanisms of water saturation. The hydrodynamically closed structures (favourable for the formation and preservation of hydrocarbon deposits) characterized by high relative and absolute contents of dissolved methane. Increased methane contents also spatially tend to transverse tectonic faults, which determines their role in the vertical transportation of water-hydrocarbon mixtures. Deep hydrodynamically closed aquifers of the Bilche-Volytsia OGBA often are marked by high nitrogen contents of non-air origin. Its source can be rock organic matter, bound rock nitrogen released during metamorphism, nitrogen of deep genesis.

Importance of Velocity Deviation Technique and Negative Secondary Porosity in Detection of Hydrocarbon Zones in Khasib Formation, East Baghdad Oil Field

The velocity deviation technique is one of the important techniques in hydrocarbon investigations, through which it is possible to identify the types and the content of rock pores. The current study aimed to demonstrate the benefit of this technique in discovering the oil sites of the Khasib formation in the East Baghdad oil field, as well as the possibility of separating the oil and gas zones by combining the velocity deviation technique with the anomalous primary porosity information that leads to negative secondary porosity. In this study, log data of three wells distributed in the study area (EB-04, EB-16, and EB-34) were used. From these data, the velocity was estimated by the sonic log, the porosity was estimated by the neutron and the density log, while the velocity deviation was determined by subtracting the velocity calculated from the density log from the sonic log velocity. The result showed that there is significant agreement between the secondary porosity values that turned positive after the oil effect was removed and the confirmed oil zones derived from the core information. Also, there was a clear correlation between velocity deviation values above -500 m/s and the permeability zone of formation, which may reflect the importance of this technique in the identification of the permeability zone. Both techniques (Velocity Deviation and log porosity analysis) can be correlated to predict the locations of gas, large-scale fractures, and unconsolidated beds in sites of high negative secondary porosity and low-velocity deviation (under -500 m/s).

Logging-based assessment of low-resistivity oil zones: A case study from Sudan

The reservoirs in the N oilfield in Sudan feature a complex sedimentary environment, which has led to a widespread development of low-resistivity oil zones, accounting for as high as 37% of the total oil zones. In this case, a large number of oil zones will be misinterpreted using conventional methods. Based on the analysis of the core data and logging curves of the study area, this study concludes that the low-resistivity oil zones are formed mainly due to the high irreducible water saturation caused by the high content of illite and smectite and complex pore structure, the additional electrical conductivity induced by clay minerals, and the difference in formation water salinity between the oil zones and water zones. Furthermore, four methods are proposed to qualitatively identify these oil zones and water zones, namely the relationship analysis of five reservoir properties, cross-plotting of sensitive parameters, analysis of pressure testing data, and multi-well correlation. Furthermore, the study quantitatively calculates the initial oil saturation using the capillary pressure data, thus avoiding the conventional empirical saturation formulas depending on electrical resistivity and solving the difficulty in calculating oil saturation of low-resistivity oil zones. Finally, precise logging processing and interpretation of 95 wells in the study area are conducted using the above-mentioned comprehensive assessment system for low-resistivity oil zones. As a result, 59 oil zones are newly discovered in 43 wells. Moreover, it is recommended that 17 oil zones in 12 wells should be tested, of which 11 oil zones have been tested as recommended, all proven to be high production oil zones after perforation. The coincidence rate of logging interpretation increases from 75% to 94.3%, and the original oil in place (OOIP) increases by 57.42 million barrels. All these indicate that the assessment system proposed is suitable for low-resistivity zones.

Experimental Study on Sweep Characteristics of Gas Gravity Drainage in the Interlayer Oil Reservoir

Stable gas gravity drainage is considered an effective method to enhance oil recovery, especially suitable for deep buried, large dip angle, and thick oil reservoirs. The influence of reservoir heterogeneity on controlling the gas–oil interface and sweep characteristics of injected gas is particularly important to design reservoir development schemes. In this study, according to the interlayer characteristics of Donghe carboniferous oil reservoirs in the Tarim Basin, NW China, 2D visual physical models are established, in which the matrix permeability is 68.1 mD and average pore throat radius is 60 nm. Then, hydrocarbon gas gravity drainage simulation experiments are carried out systematically, and a high-speed camera is used to record the process of gas–oil flow and interface movement. In this experiment, the miscible zone of crude oil and hydrocarbon gas is observed for the first time. The interlayer has an obvious shielding influence, which can destroy the stability of the gas–oil interface and miscible zone, change the movement direction of the gas–oil interface, and reduce the final oil recovery after gravity drainage. The remaining oil mainly is distributed near the interlayers. The higher displacement pressure leads to increased stability of the gas–oil displacement front and later gas breakthrough, which leads to higher oil recovery. The lower gas injection rate contributes to a slower front velocity and wider miscible zone, which could delay gas breakthrough. For the immiscible gas gravity drainage, there is a critical gas injection rate, with which the oil recovery factor is the highest.

Searching for reservoirs with bypassed oil using well tests and mathematical modeling

The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence — this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction. • The comprehensive well tests allows bypassed oil areas identification. • The presence of bypassed oil have an influence on Bourdet diagnostic plots at different time of production history. • The occurrence of bypassed oil cause obstacles for water to flow and slow down the change in conductivity. • The decrease of permeability according to the interference test results indicates the presence of bypassed oil.

Comprehensive assessment and analysis of the oil and gas potential of Meso-Cenozoic sediments in the North Caucasus

At the present stage, the development of the oil and gas industry in the Russian Federation is impossible without replenishing the raw material base, so the urgent task is to conduct investigations, prospecting and evaluation of oil and gas bearing capacity prospects in undiscovered areas. The purpose of the investigations is to analyze facies and thicknesses, choose the methodology of prospecting and exploration in reservoirs, make a comprehensive assessment of oil and gas bearing capacity prospects based on experimental investigations and construct a map of oil and gas bearing capacity prospects of the studied sediment structure. The methodology of the conducted investigations was to identify and trace zones of increased fracturing by qualitative interpretation of time seismic sections. Methods for qualitative interpretation of time seismic sections, the model of physical, chemical and geochemical criteria developed by I.A.Burlakov, gas and geochemical surveying and correlation analysis were used in the investigations. A number of prospecting criteria, established based on the analysis of reference seismic materials on well-studied areas in comparison with the results of well tests, were also used. Structural plan for forecast prospects of oil and gas bearing capacity in the studied area was made; zonal and local objects with prospects for oil and gas were identified. Graphical plotting of Eh and pH concentrations distribution and various gas and geochemical indicators allowed identifying zones of possible oil and gas accumulations and starting their detailed survey. Processing of gas and geochemical materials by means of software allowed efficient assessment of prospects for oil and gas bearing capacity of the investigated objects.

Bituminous deposits of Azerbaijan

In view of expansion of mineral resources and mineral reserves recently, Azerbaijan pays increasingly much attention to exploration and development of natural bitumen. The main bituminous deposits in the Republic adjoin oil and gas provinces (Absheron, Shamakhy–Gobustan and Lower Kuria) and zones of mud volcanism. Bitumen is genetically connected with oil and forms as a result of supergene transformations in outflow from exposed reservoirs or shallow impregnated fractures, lenses etc. Natural bitumen and bitumen produced in processing of high-viscous oil are widely used in road construction in USA, Canada and in West Europe. The current conditions and prospects for the development of commercial-value bitumen deposits in Azerbaijan are discussed. The types and classification of bitumen are described in detail. Molten bitumen resources are mostly concentrated in Klych, Kirkishlag and Airantokan deposits, and alsphaltite bitumen mostly occurs in Binagadi, Shubany and Zygilpiri deposits. The distribution and composition of bitumen are reflective of their essentially different types and qualities, which should be taken into account in feasibility study of different technologies. The most promising bitumen mining projects in Azerbaijan are Kirmaki, Binagadi, Cheildere and Shubany. Azerbaijan also holds smaller bitumen deposits such as Fatmai, Siyanshor, Baku, Digyakh, Pirallakhi, Eldaroyugu and other. These deposits are geochemically similar to the major bitumen occurrences.

Prospects for the oil and gas content of the Upper Permian deposits of the southwestern part of the Vilyui syneclise based on the analysis of sedimentary environments and geochemical conditions of oil and gas content

The article discusses the prospects for the oil and gas content of the Upper Permian deposits in the southwestern marginal part of the Vilyui syneclise. In this margin, the Permian terrigenous complex with proven oil and gas productivity in the central part of the syneclise, pinches out. The study area, represented by the monoclinal slopes of the Vilyui syneclise, is considered a promising area for the exploration of non-structural hydrocarbon traps in the Upper Paleozoic sediments. The objectives of the study include identifying general patterns of sediment formation, associated mainly with the development of the alluvial complex, and substantiating the potential opportunities of migration and accumulation of hydrocarbons in the predicted traps. The research is based on the interpretation of the latest seismic surveys and prior-years geological and geophysical data. Authors carried out structural and paleo-structural analysis, identified lithofacies in the well log, generalized and analyzed the geochemical conditions of the oil and gas content of the Upper Permian deposits, traced the pinching out of the Upper Permian deposits on the southwestern margin of the syneclise, and also outlined areas of river valleys development that form zones of advanced reservoirs. The results of the studies have validated promising oil and gas accumulation zones on the southwestern slopes of the syneclise associated with non-anticlinal hydrocarbon traps. Authors also drew up a diagram of the oil and gas potential of the Upper Permian deposits. The obtained results are of interest for prospecting for oil and gas in the area under study.

Simulation of catalytic upgrading in CAPRI, an add-on process to novel in-situ combustion, THAI

Based on the analysis of recent projections by the International Energy Agency (IEA), to meet the growing and subsequently declining demands of oil from now to 2040, we need up to around 770 billion barrels of oil. Since the worldwide total proved reserves of easy-and-cheaper-to-produce conventional oils is roughly only 520.2 billion barrels, the remaining 249.8 billion barrels must be obtained from unconventional petroleum resources (i.e. heavy oils and bitumen). These resources are however very difficult and costly to upgrade and produce due to their inherently high asphaltene contents which are reflected in their very high viscosities and large densities. However, still they should prove attractive development prospects if, as much as practicably possible, their upgrading can be performed in conjunction with in situ or downhole catalytic upgrading processes. Such projects will contribute significantly towards smoother and greener transition to full decarbonisation. Advanced technologies, such as the toe-to-heel air injection coupled to its add-on in situ catalytic process (i.e. THAI-CAPRI processes), have the potential to develop these reserves, but require further developmental understanding to realise their full capability. In this work, a new detailed procedure for numerically simulating the THAI-CAPRI processes is presented. The numerical model is made-up of Athabasca-type bitumen and it has a horizontal producer (HP) well that is surrounded by an annular layer of alumina-supported cobalt-oxide-molybdenum-oxide (CoMo/γ-Al2O3) catalyst. The simulation is performed using the computer modelling group (CMG) reservoir simulator, STARS. This new work has shown that the choice of the frequency factor of the catalytic reactions allowed model validation based on the degree of catalytic upgrading in form of API gravity. Overall, the work herein identifies the important parameters, such as API gravity, peak temperature, oil production rate, cumulative oil production, produced oxygen concentration, temperature distribution profile, extent of coke deposition on the catalyst surface, etc., governing the successful operation of the THAI-CAPRI processes. In particular, this study has shown that even in the vicinities of the mobile oil zone (MOZ) where the catalytic upgrading is expected to be taking place, the catalyst surfaces are covered with high concentration of coke. This finding is in parallel to the observations reported from experiment of CAPRI process alone. Therefore, it is concluded that when experimental studies of the THAI-CAPRI processes are to be conducted, a catalyst regeneration mechanism must be put in place in order to prolong the effectiveness and thus the life of the catalyst so that proper field operation design can be made. Additionally, the study has also shown that the temperature of the MOZ is less than 306 °C and that implies that an external source of heating the annular catalyst layer must be provided in order to effect the catalytic upgrading in the THAI-CAPRI processes. Thus, a new study should look at the feasibility of targeted heating (in the case of microwave) or conductive or resistive heating (in the case of electrical heating) to raise the temperature of the annular catalyst layer to that required to achieve the catalytic upgrading.

Hydrogeological aspects of the hydrocarbon deposit formation within the northern framing of the Caspian Lowland

The formation of oil and gas deposits in the near-port zones of the Caspian Basin is associated with the generation of hydrocarbons in deep-submerged zones and its subsequent migration to the near-port zones. The migration of oil and gas occurs together with reservoir waters. Under these conditions, the identified gas-hydrochemical anomalies in the instrument zones of the depression are important in determining the routes of hydrocarbon migration and oil and gas accumulation zones. The article analyzes the hydrogeological situation in the subsalt Paleozoic sediments in the junction zone of the Volga-Ural anteclise and the Caspian basin, describes the salt composition of reservoir waters, and the composition of water-dissolved gases. The waters of anomalous composition are identified, which indicate the predominant migration of reservoir waters towards the Volga-Ural anteclise. In the Devonian sediments of the region, anomalies are distinguished by the appearance of reservoir waters of a reduced degree of metamorphization, or their reduced mineralization (desalinated water). The identified anomalies allow us to identify zones favorable for the migration of reservoir waters and hydrocarbons, zones of oil and gas accumulation. These studies can be used to interpret the results of geological exploration for oil and gas in the port zones of the Caspian Basin.

Understanding the mobilised oil drainage dynamics inside laboratory-scale and field-scale reservoirs for more accurate THAI process design and operation procedures

The technical and economic validities of the toe-to-heel air injection (THAI) process for heavy oils upgrading and production are yet to be fully realised even though it has been operated at laboratory, pilot, and semi-commercial levels. The findings from Canadian Kerrobert THAI project suggested that there is no proportionality between oil production and air injection rates. However, this conclusion was reached without having to dig deeper into the dynamics of the transport processes inside the reservoir especially that efficient combustion was clearly taking place as the mol% oxygen in the produced gas was negligible. As a result, this study is conducted with aims of identifying the similarities and differences of the dynamics of the transport processes in lab-scale and field-scale reservoirs. For the first time, this study has found oil drainage dynamics inside the reservoir to be both scale-dependent and operation-dependent. For the laboratory-scale numerical model E, what is clearest is that all of the head of the oil flux vectors are either totally vertically directed or slightly inclined and pointing upward towards the heel. None of them is pointing backward towards the toe of the HP well. Thus, it is apparent that oil drainage pattern in this laboratory-scale model E is efficient as all the mobilised upgraded oil, including from the base of the combustion cell, is produced as the combustion front advances in the toe-to-heel manner. However, the combustion front has a backward-leaning shape which is an indicator that it is propagating even inside the HP well. This implies that the process is operating in an unstable, inefficient, and unsafe mode. These two opposing patterns at laboratory-scale must be resolved to ensure healthy combustion front propagation with efficient oil drainage and production rates are achieved. At the field scale (i.e. model F), this study has shown for the first time that there are actually two mobile oil zones: the one ahead of the combustion front with lower oil flux magnitude (i.e. MOZ) and the one containing large pool of mobilised partially upgraded oil at the base of the reservoir just behind the toe of the HP well. The above findings in model F show that there is conflicting dynamics about the goal of achieving large oil production rates downstream of the combustion front with the propagation of forward-tilting stable, safe, and efficient combustion front. If the combustion is to be optimally sustained, then most of the mobilised upgraded oil might be lost going in the wrong direction towards the region behind the toe of the HP well. In actual reservoir in the field, shale with very low permeability and porosity must be present behind the toe in order for the large pool of mobilised upgraded oil that is continuously draining from the vertical adjacent planes to be forced into the toe of the HP well. As a result, to balance these two conflicting dynamics of upward-tilted combustion front going longitudinally towards the heel of the HP well and the mobilised oil draining down at an angle towards the region behind the toe of the HP well, future studies are essentially required. These are proposed and also listed under the conclusion section in order to ensure thorough design and operation procedures for the THAI process are established.

Machine learning classification approach for formation delineation at the basin-scale

Machine learning and artificial intelligence approaches have rapidly gained popularity for use in many subsurface energy applications. They are seen as novel methods that may enhance existing capabilities, providing for improved efficiency in exploration and production operations. Furthermore, their integration into reservoir management workflows may shape the future landscape of the energy industry. This study implements a framework that generates predictive models using multiple machine learning classification-based algorithms which can identify specific stratigraphic units (i.e., formations) as a function of total vertical depth and spatial positioning. The framework is applied in a case study to 13 specific formations of interest (Upper Spraberry through Atoka / Morrow reservoirs) in the Midland Basin, West Texas, United States; a prominent hydrocarbon producing sub-basin of the larger Permian Basin. The study dataset consists of over 275,000 records and includes data fields like formation identifier, true vertical depth (in feet) of formations observed, and latitude and longitude coordinates (in decimal degrees). A subset of 134,374 data records were relevant to the 13 distinct formations of interest and were extracted and used for machine learning model training, validation, and testing. Four supervised learning approaches including random forest (RF), gradient boosting (GB), support vector machine (SVM), and multilayer perceptron neural network (MLP) were evaluated and their prediction accuracy compared. The best performing model was ultimately built on the RF algorithm and is capable of an overall prediction accuracy of 93 percent on holdout data. The RF-based model demonstrated high prediction accuracy for major oil and gas producing zones including the San Andres, Upper Spraberry, Lower Spraberry, Clearfork, and Wolfcamp at 98, 94, 89, 94, and 94 percent respectively. Overall, the resulting data-driven model provides a robust, cost-effective approach which can complement contemporary reservoir management approaches for multiple subsurface energy applications.