Oil Province Research Articles

Lithofacies, changes in mineral composition and reservoir properties of the Maykopian sediments in the Yevlakh-Aghjabedi Depression

Yevlakh-Aghjabadi depression is a well explored oil province located in the Middle Kura basin between Greater and Lesser Caucasus.The study investigates the lithofacial, mineralogical, and collector properties of the Maykopian sedimentary series within the Yevlakh-Aghjabadi depression, focusing on the Oligocene to Early Miocene epoch. Maykop deposits are widely distributed in the foothill regions of the Lesser Caucasus, both at the surface as natural outcrops and in the geological structure of deeper formations. In this article, in addition to core samples, the results of fieldworks have also been widely discussed. The conducted research indicates favorable paleogeographic conditions for oil and gas presence in these depressions. The sedimentary sequence, up to 2200 meters thick, is divided into Lower and Upper Maykopian subgroups, showing fluctuating thickness distribution. The primary source of clastic materials for the Maykopian suit is the Lesser Caucasus Mountain range. The lithological composition consists of clay, sandstones, and conglomerates, influenced by paleogeographic changes and paleochannels. Collector properties vary, with Lower Maykopian sediments exhibiting better characteristics, especially in the south-western part of the basin. The mineralogical composition dominated by fine-grained feldspars, impacts reservoir quality. Maykopian suits in the oil and gas regions of Ganja and Muradkhanli, which encompass the southernwestern and northern-eastern flanks of the Yevlakh-Aghjabedibasin, as well as conducting extensive research on reservoir properties, will enable the proper direction of future exploration activities. For this purpose, the overall condition of the Maykopian suits and the distribution of lithofacies have been analyzed, and the characteristics of hydrocarbon reservoirs have been determined. Keywords: lithology; lithofacies; Maykopian; sandy and clayey sediments; argillaceous sandstones; porosity; permeability.

A REVIEW ON CARBON DIOXIDE (CO2) – ASPHALTENES INTERACTIONS

WAG - CO2 is an oil enhanced recovery method that has been applied successfully to some of the largest pre-salt fields in Brazilian offshore oil provinces. This recovery method provides the advantage of reducing the emission of green-house gas (CO2) to the atmosphere. However, the re-injection of CO2 gas into reservoirs may also provoke deleterious effects on asphaltenes equilibria under reservoir conditions, promote pore plugging, and inflow formation damage. Thus, it is crucial that researchers investigate with caution the use of WAG- CO2 method to avoid unwanted situations. This technical contribution reviews the state of the art of WAG- CO2 recovery method, provides useful pieces of information of laboratory studies on the behavior of asphaltenes in presence of CO2, and, finally, it presents prescriptive guidelines for addressing pivotal CO2 - asphaltenes issues.

GEOLOGICAL AGE EVALUATION OF SAPELE DEEP FIELD, DELTA STATE, SOUTH-SOUTH NIGERIA

One of the most productive fields in the Niger Delta is the Sapele Deep field, an onshore field of OML 41 that is situated in the Northwestern region (Greater Ughelli depobelt) of the oil province. The Niger Delta chronostratigraphic map from SPDC (2010) and well-log, seismic, and biostratigraphic data from six wells within the Niger Delta Province were used to conduct the age assessment of the field. Petrel®2016 (Schlumberger software) was used in the interpretation of seismic and well log data used in this research. Age of rocks within the depositional basins of the study area ranges from early Miocene to late Miocene and this was established through the delineated maximum flooding surface and marker fauna from the regional seal of marine transgression which are Me-2-Bolivina-48, Me-1-Haplophragmoides-24, Tor-2-Uvigerina-8, Tor-1-Nonion-4, Ser-3-Dodo Shale, Ser-2-Cassidulina-7, Ser-1-Bolivina-25, Lang-1-Bur-5-Chiloguembelina-3, and Bur-3-Ogara Shale. The specified reference fossils from depths of 6814.5 ft to 12573 ft include Globorotalia plesiotumida, Globigerinoides extremus, Neogloboquadrina acostaensis, Globorotalia lenguaensis, Globoturborotalita nepenthes, Orbulina suturalis, Fohsella robusta, Fohsella fohsi, Fohsella peripheroacuta, Fohsella praefohsi, Praeorbulina glomerosa, Fohsella birnageae, Globigerinatella insueta, Praeorbulina sicana, and Catapstdrax dissimilis. The depth range for these markers spans from 6814.5 ft to 12573 ft.

Genesis and distribution of oils in Mahu Sag, Junggar Basin, NW China

Based on the geological and geochemical analysis of potential source rocks in different formations and the classification of crude oil types, combined with the hydrocarbon generation thermal simulation experiments, the source, genesis, and distribution of different types of oils in the Mahu large oil province of the Junggar Basin are investigated. Four sets of potential source rocks are developed in the Mahu Sag. Specifically, the source rocks of the Permian Fengcheng Formation have the highest hydrocarbon generation potential and contain mainly Types II and I organic matters, with a high oil generation capacity. In contrast, the source rocks in other formations exhibit lower hydrocarbon generation potential and contain mainly Type III organic matter, with dominant gas generation. Oils in the Mahu Sag can be classified as three types: A, B and C, which display ascending, mountainous and descending C20-C21-C23 tricyclic terpenes abundance patterns in sequence, and gradually increasing relative content of tricyclic terpenes and sterane isomerization parameters, indicating an increasing oil maturity. Different types of oils are distributed spatially in an obviously orderly manner: Type A oil is close to the edge of the sag, Type C oil is concentrated in the center of the sag, and Type B oil lies in the slope area between Type A and Type C. The results of oil-source correlation and thermal simulation experiments show that the three types of oils come from the source rocks of the Fengcheng Formation at different thermal evolution stages. This new understanding of the differential genesis of oils in the Mahu Sag reasonably explains the source, distribution, and genetic mechanism of the three types of oils. The study results are of important guidance for the comprehensive and three-dimensional oil exploration, the identification of oil distribution in the total petroleum system, and the prediction of favorable exploration areas in the Mahu Sag.

Evaluation of formation susceptibility and sand production potential in an offshore field, Niger Delta Basin, Nigeria

Wellbore instability and sand production are all common challenges in the Niger Delta oil province, resulting in high drilling and production cost as well as damage to oil facilities. The vulnerability of lithologic formations to wellbore instability and resultant sand production is investigated in the four delineated reservoirs of the “Areo” field, western part of Niger Delta Basin. The foundation for establishing the geomechanical properties in this study was a 1-dimensional mechanical earth model, using gamma ray (GR), density (RHOB), compressional slowness (DTC), and shear slowness (DTS) logs. Within the Areo oil field, two wells (well 001 and well 002) were correlated. The evaluated formations are still primarily composed of compacted shale and unconsolidated sandstone, with reservoir sand units exhibiting lower elastic and rock strength properties than shale units. High compressibility and porosity make sand more brittle, while low compressibility and porosity make shale stiffer due to high moduli. The maximum force that can be applied to a shale unit without causing it to fail is 17.23 MPa, which is the maximum average rock strength of the shale. It means that shale requires more vertical stress or pressure than sand does in order to deform it (15.06 MPa). The three sand prediction approaches used in the analysis of sand production predictions have cut-off values that are higher than the average values of the formations. The Schlumberger sand production index method (S/I) indicates that the reservoir has potential for sand influx in the two wells, with the average of the four reservoirs studied in wells 001 and 002 being 1.55 × 1012 psi and 1.14 × 1012 psi respectively. However, when a formation's sand production index is less than 1.24 × 1012 psi, as it is in this study, the formation is likely to produce sand. These findings support the notion that the defined sandstone units are highly unconsolidated and have a high potential for producing sands; therefore, sand control techniques must be factored into process optimization and cost reduction plans.

How transnational rules can contribute to the improvement of the Brazilian regulatory system for unitization—an analysis under the transnational legal order perspective

Abstract Unitization is the most effective method to avoid irrational, wasteful and environmentally unsustainable production of oil and natural gas. Therefore, it is important to notice that unitization is a complex practice. It is effective for the equitable production division of a deposit shared by different owners. However, compulsory membership can result in costly negotiation and make exploration and production projects less attractive. In the pre-salt, the most productive Brazilian oil province, unitization processes are common and even more complex due to the following factors: (i) there are three different tax regimes in the pre-salt polygon; (ii) when the reservoir is shared with an area not granted yet (referred to as an open area), the Brazilian regulation establishes that the unitization process must be carried out with the public company, Pré-sal Petróleo S.A., representing the Government; (iii) moreover, due to the high productivity of the pre-salt layer, the financial values involved in this process are substantial, even with a participation of less than 1 per cent in the shared reservoir. Brazil established a robust regulation on unitization in 2013, which was amended in 2017 and, again, in 2020. This demonstrates that the regulatory improvement process, in the search for a more efficient regulation—that balances the attraction of investments and protection of the public interest—is continuous. This article proposes that in this process of regulatory improvement, good international petroleum industry practices (good practices), contractual models drawn up by industry associations and codes of conduct shall be used as a reference. These non-state rules, which are the result of self-regulation by the upstream sector of the oil industry, will be considered in this article as transnational rules, following the approach of Halliday and Shaffer, who propose the existence of a transnational legal order.

Geochemical characteristics of oils from the Sooner Trend Anadarko Basin, Canadian, and Kingfisher Counties and South-Central Oklahoma Oil Province plays, Anadarko Basin, Oklahoma

Geochemical characteristics of oils from the Sooner Trend Anadarko Basin, Canadian, and Kingfisher Counties and South-Central Oklahoma Oil Province plays, Anadarko Basin, Oklahoma

Pore systems and organic petrology of cretaceous Mowry and Niobrara source-rock reservoirs, Powder River Basin, Wyoming, USA

The Powder River Basin (PRB) is a world-class oil province, in large part thanks to contributions from premier source rocks, Cretaceous Mowry and Niobrara shales. Both formations are also unconventional reservoirs. A critical aspect of evaluating production potential and finding sweet spots is the nature of the pore systems in these fine-grained source-rock reservoirs. Variation by stratigraphic interval is important for selecting optimum target zones for horizontal wells. Understanding variation in pore type, size, and connectivity and relationships with mineralogy and fabric help in determining prospectivity in different parts of the basin. Deciphering controls on pore-system development helps predict intervals and locations of optimum reservoir quality.Imaging of Niobrara and Mowry samples from a range of thermal maturities provided observations and data on pore systems, organic matter (OM) types and associations with mineralogy and fabric, wettability, and microporosity associated with both diagenetic and detrital clays. Imaging techniques included scanning electron microscopy, organic petrography and correlative scanning electron microscopy, and mapping of mineralogy through energy dispersive spectroscopy.Mean solid bitumen (BRo) and vitrinite reflectance (VRo) values indicate all samples are in the oil window with values ranging from 0.52 to 1.15%. Organic fluorescence is prominent in amorphous OM, solid bitumen and some vitrinite in the early oil window. The fluorescence is extinguished at higher thermal maturity. Carbonate pellets (in Niobrara) mainly contain migrated solid bitumen and residual live oil and little or no terrigenous OM (vitrinite and inertinite). However, terrigenous OM is common in siliceous/argillaceous laminae in both formations, where it occurs with amorphous OM, some of which has converted in situ to a solid bitumen petroleum residue.One key finding is the widespread presence of migrated OM at very early oil window maturity. Distribution of such OM and associated wettability alteration is fabric-controlled, at all levels of thermal maturity studied. Clay morphology and abundance and supporting rigid mineral grain framework strongly influence pore development, preservation, and connectivity in both formations. Carbonate content is a good proxy for reservoir quality in Niobrara intervals due to association of porous solid bitumen with calcareous fecal pellets. High recrystallized microquartz content is associated with the best reservoir intervals in the Mowry.

Characteristics, Types, and Prospects of Geological Sweet Sections in Giant Continental Shale Oil Provinces in China

Characteristics, Types, and Prospects of Geological Sweet Sections in Giant Continental Shale Oil Provinces in China

Implications of groundwater flow on preservation of heavy and extra-heavy oil accumulations in Southern Llanos Basin, Colombia

The southern sector of the Llanos Basin in Colombia is a heavy and extra-heavy crude oil province where it has been hypothesized that hydrodynamic flow has influenced the potential of hydrocarbon storage and production. In this area, the hydrodynamic flow and the geochemical nature of the fluids are thought to decrease the potential for hydrocarbon retention. This work provides a comprehensive view on the impact of the regional hydrodynamic flow on the retention of the heavy oil accumulations present in the reservoirs that are part of the most important regional flow unit identified in the Southern Llanos Basin. The Basal Flow Unit (BFU) constitutes a basin-scale flow unit that hydraulically and laterally connects rocks from the Cretaceous (west) to the Oligocene (east) and extends from the basin's southwestern margin up to hundreds of kilometers within the Llanos foreland basin, and whose main water recharge zone has been identified towards the eastern flank of the Serranía de la Macarena. To understand the impact of the physicochemical properties of the fluids on hydrocarbon retention, we analyze the relationship between hydraulic data and the main characteristics of the fluids present in the BFU as well as their spatial distribution. This analysis integrated information from hydraulic heads, SARA analysis (Saturates, Aromatics, Resins, and Asphaltenes), Whole Oil Gas Chromatography analysis, API-gravity, and oil densities. In addition, hydrochemical analyses of the primary ions were performed in groundwater samples from the BFU, which was integrated with deep resistivity data measured in producing and exploratory oil wells in the area. The results allowed identifying the southwestern corner of the southern Llanos Basin as the area with the highest hydrodynamic flow impact, and therefore, the area with the least potential for hydrocarbon retention. We attribute the main causes to: 1) the proximity to recharge areas, and 2) the low contrast of fluids densities (freshwaters and highly biodegraded heavy crude oils), implying high Tilt Amplification Factor (TAF) values (10–100). In addition, the highest values of hydraulic heads (200–400 m), groundwater with the lowest ion concentrations (up to < 5 ppm Cl−), highly biodegraded crude oils, and the presence of poorly developed geological structures with low dip angles occur in this area, which allows us to interpret that the water washing process has decreased the hydrocarbon retention potential for this sector of the Llanos basin. Furthermore, gradual changes in resistivities (decreasing eastward) and ions concentration (increasing eastward) in groundwaters suggest the eastern flank of the Serranía de la Macarena as the main recharge zone of meteoric waters into the BFU. Finally, numerical simulation techniques were used to analyze the behavior of hydrocarbon drainage under hydrodynamic conditions, obtaining a first approximation to the average linear groundwater flow velocities between 10−3 and 10−4 ft/day.

Substituting Locally Sourced Carbon Nano Particle with the Conventional Additives

Nanoparticle drilling fluids have the potential to minimize wellbore instability problems. There is a need for the development of a new generation of drilling fluids to handle wellbore instability problems especially in lost circulation zones and shale problems. A rheological model is needed to accurately describe the rheology of nano base drilling fluid because limited experimental data are currently available for using carbon nano particles in water base mud and Inability of current methods to address shale strength with increased open hole time reduction of critical mud weight to prevent hole collapse in challenging environment like depleted formation, narrow margin, HPHT wells. The study attempted to produce nano particles locally where the in-situ formation of floating catalyst was used. It involved the floating of catalyst particles by thermal decomposition of organometallic where argon, acethelene and nitrogen gas were used. The CNP WBM formulation was compared with the conventional base mud. Result Show that the CNP mud gave a better result for the fluid loss which can be used as a fluid loss property in the study mud, CNP gave 6.2mls while soltex gave 8.2mls and also CNP gave a thin and firm filter cake of 0.18cm as compared to the soltex formulated mud. Therefore, CNP is a good fluid loss additive and enhances the rheological properties of mud, also helped to improve and add value to local content in the oil and gas industry and save us the cost through the application of locally sourced drilling fluid and save foreign exchange and It has export potentials in the Gulf of Guinea and other oil provinces.

Excellent source rocks found along the margin of a large lacustrine basin: Case study from the Ordos Basin, China

Whether the Chang 6 oil pools of the Triassic Yanchang Formation in the Ansai-Yanchang (AY) oil province on the Yishan slope of the Ordos Basin formed from near source rock or far source rock has long been debated. An understanding of the source rock's position will impact the formation mode and distribution of accumulations in this area. Based on the geochemical data of the Chang 7 source rock in six wells and 18 crude oil samples, the geochemical characteristics of Chang 7 source rock and its relationship with Chang 6 crude oil were studied. There are two types of source rocks, namely, black shales and dark mudstones, present in the AY area. The gross thickness of the Chang 7 black shale is 3.0–19.7 m, with a distribution area of 5500 km2. It has an average total organic carbon (TOC) content of 3.34%, with a chloroform bitumen “A" content of 0.512%, indicating good to excellent source rock potential. The kerogen assessment with core samples shows mixed type I-II1, and has reached peak oil generation, maximum pyrolysis temperatures (Tmax) ranging from 445 to 458 °C. In contrast, the average TOC content of the dark mudstone in Chang 7 is 0.91%, chloroform bitumen “A” is 0.079%, the main type of kerogen is type II2-II1, and Tmax varying from 446 to 461 °C, indicating only fair source rock potential overall. The Chang 7 source rocks in the AY area have a gammacerane index of 0.07–0.38, with an average value of 0.21, which reflects a low-salinity fresh to brackish water environment. The relative abundances of C27, C28, and C29 steranes are 29.7%, 23.1% and 47.2%, respectively, indicating that terrestrial higher plants and aquatic organisms provide similar contribution in the Chang 7 source rocks. Oils produced from the AY area of the Chang 6 member have similar geochemical signatures, but are significantly different from the Chang 6 crude oils in the Daozhen (DZ) area of Ganquan County and the Huaishuzhuang (HSZ) area of Fuxian County, which are located in the center of the lacustrine basin. They differ in terms of the maturity of the oil samples and the microscale composition of the parent material type. The closer the wells are to the center of the lacustrine basin, the higher the maturity of the source rock and the greater the contribution of aquatic organisms. The variation of carbon isotopic composition of Chang 6 crude oil in AY area is consistent with that of Chang 7 shale locally, but opposite to that of Chang 6 crude oil in DZ area. The ratios of nC21-/nC22+, tricyclic terpane/hopane and C29 sterane ββ/(ββ+αα) biomarker parameters of Chang 6 crude oils in AY area are similar to those of Chang 7 shale in local area, but deviate from those of DZ and HSZ area. These data results reveal that the Chang 6 crude oils in the AY oil province are dominated by the local Chang 7 excellent source rocks rather than by the long-distance migration of oils from the basin center.

The Oil Palm Governance: Challenges of Sustainability Policy in Indonesia

Nowadays, Indonesian palm oil faces agrarian, environmental, and social issues and has been subject to sharp criticism from the international community for many years. To answer this problem, the Indonesian government implemented a strategy through certification which ensured the achievement of sustainability standards, especially on the upstream side of the palm oil supply chain. The implementation of Indonesian Sustainable Palm Oil (ISPO) was an ultimate instrument that applied in particular to smallholders oriented towards managing land legal issues, plantation business licenses, plant seeds, and environmental management and to farmer organizations at the local level. However, this process faced quite complex challenges in the form of structural barriers that are very constraining. This study revealed the occurrence of the phenomenon of hollow governance when regulations are absent or collide with each other. The study also revealed institutional power and multi-level governance that made the governance process ineffective or counterproductive. With a qualitative approach to research conducted in three important palm oil provinces of Indonesia, this article aims to look at the issues of oil palm governance a bit more comprehensively. The study conceptualized what was referred to as low-functioning governance to describe how weak the institutions, organizations, actors, and resources are that support ISPO implementation, especially at the regional and local levels. This paper suggests improving and strengthening the ISPO oil palm governance if Indonesian palm oil companies and smallholders want to gain better credibility on sustainability abroad.

The potential of sites in Yakutia is greatly underestimated, we are talking about the opening of a new oil and gas province

The potential of sites in Yakutia is greatly underestimated, we are talking about the opening of a new oil and gas province

Extraction concentrating of the acid-soluble forms of rare earth elements from oils of the Volga-Ural oil and gas province using rotating coiled columns

Trace elements in oils are the natural markers of the oil origin of and the mechanism of oil genesis. Direct determination of rare earth elements (REE) in crude oils is rather difficult due to their low concentrations (10–6 wt. %). Information about the forms of trace elements in oils is of particular interest. The goal of the study is determination of the content of acid-soluble forms of REE in oils from various fields of the Volga-Ural oil and gas province. Six samples of oils of heavy and medium density and viscosity were analyzed. Extraction of acid-soluble forms of REE was carried out using rotating coiled columns in 0.5 M aqueous solution of nitric acid. Toluene was used to dilute the oils up to the necessary values of the density and viscosity providing the possibility of extraction in the system aqueous acid solution – oil. The content of REE was determined by inductively coupled plasma mass spectrometry on an Agilent 7900 spectrometer. Their content in an acid-soluble form in oil samples under study ranged within 172 – 2173 ng/kg. Such a wide range of values is attributed to the difference in the geology and age of deposit formation. The highest content of acid-soluble forms of REE (2173 ng/kg) was observed in the oil sample from the Novo-Elkhovsky field, whereas the lowest value (172 ng/kg) was measured in the oil sample of the Pioneer field. It is shown that the content of acid-soluble forms of REE depends on tectonic zoning, productive horizons and layers, as well as on the physical and chemical properties of oils. The distribution of acid-soluble forms of light and heavy REE was evaluated. Most of the REE (75 – 99%) determined in the analyzed oil samples are light REE. It is noted that systematization of the data on the properties of oils, geological and geochemical characteristics of the deposits will provide reliable forecasting of the various forms of REE present in oils.

Improving the Efficiency of Managing the Development of the West Siberian Oil and Gas Province Fields on the Basis of Differentiation and Grouping

Abstract —Using image recognition methods (principal component method (PCM) and discriminant analysis) made it possible to group and identify more than 500 research objects developed in five oil and gas areas of the West Siberian oil and gas province (WSOGP), which are confined to 13 large tectonic structures and 10 productive horizons. The grouping was made according to 19 parameters characterizing the mode of oil and gas occurrence and the geologic–physical and physicochemical properties of the reservoirs and hosted fluids exerting a prevailing influence on the recovery of oil reserves and used on projecting the development of research objects. The performed study has identified 19 relatively homogeneous groups of objects, each having a specific set of geologic–physical properties. It is shown that the parameters reflecting the geologic–physical and physicochemical properties of the reservoirs and fluids within the identified groups of objects exert different effects on the recovery of oil reserves. This requires differentiation and grouping of the objects during the solution of various development problems. It has been established that the specific features of groups of objects are determined primarily by areal, tectonic, and stratigraphic factors and that grouping must be performed separately in each stratigraphic system. Algorithms are proposed for grouping the developed oil and gas fields and for searching for groups of analogous objects in fields out of exploration that are most similar to the developed ones. The performed grouping and the results obtained provide the necessary information about the research objects and increase its reliability, thus making it possible to improve the efficiency of managing the oil company assets, i.e., the WSOGP oil fields.

An optimisation model for incentivising the development of marginal oil and gas fields amidst increasingly complex ownership patterns: UKCS case study

Many recent discoveries in the UKCS have been economically marginal and comparatively small such that they are unable to be developed on a standalone basis. Nevertheless, there is a proliferation of production facilities and transport infrastructure that can, on accepting a tariff, process hydrocarbons from these smaller-sized oil and gas fields, thereby contributing to the UK Government's strategy of maximising economic recovery (MER). However, the empirical dimensions of cost-sharing arrangements between a field owner (host field or hub) and tie-in (satellite) fields are not well examined in the literature although they influence long-term economics in matured oil provinces. In this paper, we develop a mixed integer programming optimisation model to analyse how these third-party access to infrastructure issues impact MER in the UKCS. A first-best situation with only one regional operator is empirically compared with the actual situation of multiple ownership. We then assess the impact of different infrastructure unbundling provisions via pipeline tariff choices and their interaction with the fiscal regime on the net present value (NPV) and other project metrics such as timings of hub and field shutdowns. We find that differences in field ownership, tariff choice and changes to the fiscal regime impact the overall NPV of field developments. Our results also show that having a progressive fiscal regime in a mature basin such as the UKCS is important to support continued operations under low oil prices while increasing the government's take at high prices. The cost-sharing effect shows that imposing strict cost-sharing rules does not change overall project valuations, even in a low oil price scenario. An additional contribution to the extant literature is that tariff determination could be based on cost-sharing rules that enjoin each field tieback to a hub to pay a split tariff, comprised of a fixed cost of service (access charge) and variable (marginal) costs. • Presents MIP model for analysing economic dependencies of infrastructure assets. • Ownership style, choice of tariffs, and fiscal regime impact overall field value. • Reducing marginal tax rates improves profitability, reflecting neutrality and progressivity. • Tariffs are decisive as to whether satellite or user fields are developed. • Tariff determination to maximise MER should be based on two-part cost-sharing.

The use of data on capillary pressures in the development of deposits in the Middle Ob region

Currently, most of the oil fields in the West Siberian oil and gas province are in the final stage of development. There is water-cut in production, a decrease in oil production, and the structure of residual reserves deteriorates. The search and application of the most successful scientific methods and technologies for improving oil recovery in the development of fields is quite an urgent task.It should be taken into account that hydrophobic reservoirs are common in the oil fields of Western Siberia, and when applying the method of reservoir flooding, this fact should be taken into account and a more detailed approach should be taken to the study of capillary forces to prevent flooding of productive objects. Despite the good knowledge of the West Siberian megabasin, some fundamental issues of its structure and oil and gas potential remain debatable.The article proposes methods for improving oil recovery of the BS10 formation of the Ust-Balykskoye oil field based on the study of capillary pressures in productive reservoir formations, and provides recommendations for the placement of injection wells. The study of the capillary properties of reservoir rocks will significantly improve the efficiency of exploration and field operations in oil fields.

Analytical review of underground equipment of water impact operation for well development

Rational indicators for the development of oil and gas fields are related to the systemic maintenance of a given level of perfection of formation opening in bottomhole zones of producing or injection wells. This need arises with the colmatation of the natural collector by mechanical, asphalt and tar-paraffinic particles, leading to a decrease in productivity, acceptance of wells and the need to restore the inflow by methods of artificial action on the bottomhole formation zone. Analysis of the effectiveness of the application of various methods of stimulating the flow of reservoir products in the fields of the Timan-Pechora oil and gas province (based on field data) allowed to argue the success of using hydraulic fracturing, thermogas chemical, and shock-depressive effects on the bottomhole formation zone. The prospect of the development of technical means for impact-depressive (implosion) impact on the bottomhole formation zone favorably distinguished by simplicity, cheapness, manufacturability and accessibility is shown. The designs of implosion hydrogenerators of single and multiple pressure are analyzed, shortcomings of technical devices are identified and ways of improving mechanisms are outlined. The results of effective application of various downhole generator devices for increasing productivity and well acceptance are presented.

International Comparison of Nigerian Petroleum Fiscal Regime with the US, UK and Norway: A Real Option Analysis on Deepwater Projects Investment

Given the mission of the international oil companies which is to find, develop, refine and market hydrocarbon resource in a fashion that achieves the highest economic returns to the owners coupled with the competitiveness of attracting international investment capital, it follows then that oil producers would give priority to oil provinces or regions with economically attractive petroleum fiscal regime that could aid their mission. The relationship between taxation of mineral resources and investment attraction for efficient recovery of hydrocarbon resource has been established by compelling theories. However, the fact that the behavior and effect of fiscal regime on investment decision are not apparent without detailed economic analysis makes empirical analysis imperative. Thus, this study investigated the economic efficiency and competitiveness of international petroleum fiscal regime using real option analysis in Gulf of Guinea, Gulf of Mexico, and the North Sea with sampled Petroleum Fiscal System in Nigeria, The United States, The United Kingdom and Norway. The economic impacts of the fiscal regimes were estimated by real option analysis methodologies for Large and small new oil fields development. Three future oil prices of $30, $45 and $60 per barrel were considered for the economic analysis. For large oil fields, under the worst case oil price of $30 per barrel, the post-tax option values per dollar investment were $0.67, $0.95, $0.54 and $0.60 respectively for Nigeria, The United States, The United Kingdom and Norway showing the United States as preferred investment destination for international investors. However, for a small oil field, Norwegian fiscal system promises better returns than any of the other oil provinces particular during adverse operating conditions.