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An algorithm was developed to automate processing of large datasets of Earth remote sensing. The algorithm was developed and implemented in the form of an M-Processor program in the Python programming language using the modules of the ArcGIS Desktop 10.2 software, which allows complex calculations without spending additional time on programming and reduces the number of manipulations for calculating separate desired characteristics. The implementation of the developed algorithm is considered on the example of ice data processing for the Sea of Okhotsk according to the data of the Multisensor Analyzed Sea Ice Extent – Northern Hemisphere (MASIE-NH) with a spatial resolution of 1 and 4 km and an ice-cover zoning mask.

The paper presents the results of statistical processing of data on the thickness and size of the tephra fragments of andesidacite composition erupted as a result of a phreatic explosion in the caldera of Golovnin volcano about 1000 years ago. A petrochemical description of the products of volcanic activity of the crustal Golovnin volcano and its evolution process is presented based on geological and geophysical data. The relationship between the thickness of the tephra, the size of its fragments, and the distance to the eruption center was studied using the polynomial regressions of varying degrees and exponential distribution. The adequacy of the constructed models to the initial data is illustrated by determination coefficients. Tephra distribution models were constructed on the basis of a three-dimensional trend analysis. For the first time, a logarithmic model was used to describe the size of tephra fragments. The accuracy of the model used was estimated. A method for estimating the potential dispersion range of tephra fragments of a certain size was obtained. The work demonstrates the potential of mathematical statistics for describing the distribution of products of volcanic eruptions of a certain type. The results of this study are suitable for creating an information database of pyroclastite distribution across the Kuril-Kamchatka volcanic region.

The Kuril island arc is an important element of the Pacific transition zone, within which such modern geological processes as underwater gas-hydrothermal activity occur. The study of underwater gas-hydrothermal activity, which affects the natural environment and all life activities, has not only fundamental but also a great practical importance. The article provides a review of research studies into the underwater gas-hydrothermal activity of the Kuril island arc. New information on the manifestations of underwater gas-hydrothermal activity within this zone obtained as a result of processing, revision and analysis of materials of complex volcanological shipboard studies at the Volcanolog research vessel (1981–1991) is presented.

Heat exchange between the three media – water, ice and air – must be taken into account when predicting the ice dynamics, drift and redistribution. It is known that the components of the heat balance vary quite strongly depending on the boundary of which media they are considered. Evaporation and turbulent heat exchange with the atmosphere are great in the areas of pure water, while evaporation from the surface of ice and snow is much less pronounced. To study the appearance of ice, it is necessary to consider only those environments between which intense heat exchange takes place; these environments are water and the atmosphere. This article studies the thermodynamic processes occurring over the seawater area by the statistical method of correlation analysis using the data on air temperature collected at hydrometeorological stations and those on the ice area from open sources. A new predictor is proposed, indicating a high correlation of 0.90–0.95 between the sum of degrees of daily temperature difference at the hydrometeorological stations of Okha and Oymyakon and the data on the area of the sea ice in the northwestern region of the Sea of Okhotsk on the last day of the month.

In the article by N.A. Sycheva and L.M. Bogomolov, the authors proposed to combine the interrelated data on the stress drop in the earthquake sources, ∆σ, and reduced seismic energy, ePR, to analyze the dependence of these parameters on earthquake scale along with expansion of the measurement statistics (assessments). The dependence of these parameters of a source on the seismic moment or on the earthquake magnitude within 2.2 ≤ М ≤ 4.0 magnitude range has been determined using the example of the Northern Tien Shan (Bishkek geodynamic polygon with the KNET network). The author of the letter to the editor notes the article conclusions to be limited, because such relationship is only manifested within the more or less narrow range of the magnitudes. Attention is also drawn to the semantic difference between the ∆σ and ePR parameters. It is the reduced seismic energy that reflects the mean strain in the source area, and its appliance to the analysis of scale dependences of earthquake sources is more informative.

This article describes the process and results of the development and testing of a cost-effective, portable, safe to move by air geophysical pulse voltage generator for seismic exploration of the subsurface. The generator is based on high-speed power electronic keys of a new generation consisting of an insulated gate bipolar transistor or a field-effect transistor based on silicon carbide, a compact power converter of alternating voltage from an autonomous generator or electric network to direct voltage using pulse-width modulation and current or voltage stabilization depending on the mode set by a researcher. Field tests were conducted to confirm the suitability of the developed design of the generator and the correctness of the chosen parameters of its elements. To this end, a detailed analysis of the effect of the developed geophysical generator on the parameters of the geoenvironment was carried out.

The work presents the results of a retrospective analysis of the seismicity of Sakhalin using the LURR method of mid-term earthquake prediction for 1997–2019. All previously performed computations are reduced to a single database of seismological data (catalogue) of the Sakhalin Branch of the Federal Research Center “United Geophysical Survey of RAS”. Similar to previous studies, the Sakhalin territory was scanned by applying computational areas in the form of circles with a radius of one degree; however, the resolution was increased. The entire territory was covered by such zones with a step of 0.5 degrees in latitude and longitude, with the grid being detailed down to 0.1 degrees in three most dangerous seismogenerating zones. As a result, the number of computational samples was increased, which allowed the omission of anomalies in the LURR parameter during computations to be avoided. Due to a reasonable binding of the lower bound of the magnitude for predicted events to the upper bound of the magnitude range of the computational sample (M = 5), the number of objects for the retrospective forecast was increased by 3 times for the study period. 323 computational samples (119 of which are basic and 204 ones are detailed) were processed on the territory of the island. 15 alarm periods were obtained, which geographically represent all zones of moderate and strong earthquake generation on Sakhalin Island. As a result, 17 out of 19 earthquakes with M ≥ 5 occurred in the areas with anomalies during the alarm periods not exceeding three years. Out of 15 periods, 4 turned to be false. Thus, 75 % of the alarms predicted 89 % of the earthquakes.

Для верификации представлений о неотектонических и современных напряжениях Сахалина анализируются структурно-геоморфологические признаки напряженного состояния этого региона, обнаруженные в ходе полевых работ 2019–2020 гг. Наряду с новыми полевыми замерами структурно-геоморфологическим методом представлены данные о деформации земной коры на основе GPS/ГЛОНАСС-измерений. Приводятся данные геофизических исследований (сейсмологических и скважинных методов). Подтверждено выделение трех типов областей с различной геодинамической обстановкой растяжения, сжатия и чистого сдвига. Отмечены вариации современного поля напряжений на границах областей с различной геодинамической обстановкой формирования новейших разломов. Северный Сахалин имеет специфические направления осей сжатия неотектонических напряжений, выраженные в северо-восточных ориентировках, в отличие от преобладающих субширотных ориентировок на всем острове. Проведенные исследования показали, что на юге Сахалина граница между Амурской и Охотской микроплитами проходит, скорее, по Западно-Сахалинскому, а не по Центрально-Сахалинскому разлому.

Поиски локальных газовых аномалий в акваториях необходимы для повышения безопасности строительства морских нефтегазопромысловых сооружений. В статье изложены результаты исследований в 2010–2017 гг. геологических опасностей на Южно-Киринском нефтегазоконденсатном месторождении с применением сейсморазведки высокого разрешения. Построены новые высококачественные сейсмические разрезы, приведенные к единому виду и уровню, что позволило выполнить корреляцию отражающих горизонтов и картировать геологические опасности на пересекающихся площадках исследований разных лет. По результатам интерпретации сейсмических разрезов обнаружены локальные аномалии в верхней части разреза, свидетельствующие о наличии газа. По структурным особенностям напластования на сейсмических разрезах обнаружен турбидитовый поток на глубине 900 м от морского дна с шириной 1000 м и протяженностью более 2.5 км. Выявлены корреляционные зависимости между амплитудой на сейсмическом разрезе и значением содержания метана (С1) в промывочной жидкости на каротажной диаграмме. Итогом работы служит впервые построенная сводная карта всех геологических опасностей в пределах Южно-Киринского нефтегазоконденсатного месторождения, обнаруженных в результате интерпретации сейсмических разрезов.

The Ebeko volcano located in the northern part of Paramushir Island (Northern Kuril Islands), is currently the most active volcano of the Kuril Island arc: since 2016, next explosive eruption has continued, proceeding in the form of regular ash-gas explosions of moderate force. In the period from January 2018 to October of 2020 a total of at least 1834 emissions were recorded (during daylight hours and under good weather conditions). In May–July 2020, the intensification of the eruptive activity of the volcano was observed, that manifested in a sharp increase of the emissions frequency and height. During this period, 296 emissions were recorded, 90 of which were at an altitude of 3 km or more.

The work presents modern data on the location, morphometry, and genesis of the largest lakes basins of the Kuril Islands obtained in the volcanological expeditions of the IMGG FEB RAS during 2005– 2018 and using open geographic information resources. 1099 lakes were sampled according to the criterion S ≥ 1 km², the list of studied objects included 20 reservoirs, represented by 7 volcanic and 13 lagoon lakes. The considered lakes are clearly divided according to their origin, area and height of the mirror, and maximum depth. The most part of large lakes falls on the Southern Kurils, and the largest water body – the volcanic lake Koltsevoe – is located on Onekotan Island, which is a part of the group of the Northern Kurils. Volcanic lakes occupy an area of 48.26 km² (60 % of the total area of 20 lakes), the depth varies in the range from several tens to several hundred meters. This category of lakes is characterized by relatively high levels of the mirror, which range from 50 to 648 m above sea level. Lagoon lakes occupy an area of 32.15 km² (40 % of the total area of 20 lakes), the depth of water bodies is small – from 1 to 23 m, the absolute height of the lake mirror is from 1–5 to 8–9 m.

Reliable short-term tsunami forecast on the Kuril Islands when earthquakes occur in the Kuril-Kamchatka Trench is the most difficult. Forecasting by the traditional magnitude method often leads to false tsunami alarms. Based on the examples of the events of 2006, 2007 and 2020 on the Kuril Islands, as well as the event of 2018 in Alaska, it was shown that according to the data of the ocean level measuring stations closest to the tsunami source (tsunami travel time is 10–20 minutes) it is possible to adequately predict the tsunami near the coast. Calculations of tsunami waveforms near the coast from data containing seismic noise have shown that the resulting waveforms contain high-frequency oscillations. However, these fluctuations do not interfere with the assessment of the real waveform and the danger of the expected tsunami. In contrast to forecast methods based on the magnitude criterion, the applied method of short-term tsunami forecast makes it possible to calculate the waveform: the amplitudes of the first, maximum waves, their arrival time at a given point and the estimated duration of the tsunami. The proposed method can become a tool that will improve the quality of operational tsunami warning, significantly reducing the number of false tsunami alarms.

The paper provides with the research results of physicochemical and balneological properties of thermal waters and hydrothermal mud of the Ebeko volcano (Paramushir Island, Kuril Islands). To assess recreational and tourist potential, we sample the most intensive thermal waters outputs. Ultra-acidic spring no. 1 of the Verkhne-Yuryeva group has a temperature of 88 °C, its mineralized (M – 13 g/l) chloride-sulfate waters contain biologically active elements in elevated concentrations (Si, B, Br, Fe2 +). Thermal waters of the Verkhne-Yuryeva springs can be roughly attributed to the Gaisky type of the acid water group and recommended for external use in the treatment and prevention of a wide range of diseases. Given the complexity of the route to the springs, the real development of this territory is considered not as a balneotherapy complex, but as an object of recreational and tourist activities. A similar situation is with an ultra-acidic sulfate thermal spring in the North-Eastern solfataric field. In addition to hydrotherms, it contains thin deposits of hydrothermal mud , which is almost impossible to use as a therapeutic due to its insufficiently good physical indicators and relatively small volume. The most promising deep hydrotherms for recreation and balneotherapy are opened by a well P-2 in the area of Severo-Kurilsk. In 2014, the hydrotherms temperature was 82 °C, mineralized water (M – 8.6 g/l) chloride-hydrocarbonate sodium, slightly alkaline (pH 7.6), with an elevated content of biologically active components (Si, B, Br). According to the physical and chemical properties, the thermal waters of well P-2 can be tentatively attributed to the Lazarevsky hydrochemical type of therapeutic drinking water of chloride-hydrocarbonate sodium group, and as an external (balneological) use, they are tentatively close to the Kuldur type of siliceous thermal waters of various ion composition.

A generalization of the results on the stress drop and the specific seismic energy for the earthquakes in Northern Eurasia has been made. The relationship of these parameters with the seismic moment and the magnitude has been analyzed. Detailed studies for the Northern Tien Shan (Bishkek geodynamic polygon) were carried out, the values of the dynamic parameters of the sources for 183 earthquakes of various energy classes (K = 8.7–14.8) were obtained: angular frequency, spectral density parameter, scalar seismic moment, source radius, stress drop level, seismic energy and specific seismic energy. Two models have been used to compute the source radius and the stress drop – the Brune approach and the improved Madariaga–Kaneko–Shearer model. For relatively weak events, a power-law dependence (regression) of the stress drop on the scalar seismic moment M0 has been identified, that complies with the results on the power-law dependence of the specific seismic energy on M0 in a number of other regions of Northern Eurasia. The relationship between the type of source movement and the stress drop level has been noted as well.

The exploitation and exploration of shale gas is of great values to solve the energy problem. Taking the shale from Silurian Longmaxi formation in Sichuan Basin as an example, its geological characteristics and reservoir chemical reaction under the action of fracturing fluid were analyzed, and moreover, a series of data determination and fracturing fluid chemical reaction experiments were carried out. The results showed that the average total organic carbon value of shale in the study area was 4.79%, the kerogen type was type I, the ratio of aliphatic structure to aromatic structure was smaller than 1, the average RO value was 2.15%, the content of clay mineral in the mineral composition was high, the average porosity was 3.16%, and the average permeability was 0.036 × 103 μm2, which was conducive to shale gas generation; under the action of fracturing fluid, the sulfate mineral in the shale dissolved, clay mineral expanded, and the pore volume and specific surface area reduced. The results verify that the research area has shale gas mining value, and this study makes some contributions to further study the optimization of fracturing fluid and improve exploitation technology.

The process of “hysteresis” has widely attracted the attention of researchers and investigators due to its usage in many disciplines of science and engineering. Economics, physics, chemistry, electrical, mechanical, and petroleum engineering are some examples of disciplines that encounter hysteresis. However, the meaning of hysteresis varies from one field to another, and therefore, many definitions occur for this phenomenon depending on the area of interest. The “hysteresis” phenomenon in petroleum engineering has gained the attention of researchers and investigators lately, because of the role that plays in reservoir engineering and reservoir simulation. Hysteretic effects influence reservoir performance. Therefore, an accurate estimation of rock and fluid property curves has an essential role in evaluating hydrocarbon recovery processes. In this paper, a comprehensive review of research and growth on the hysteresis of wettability for its applications in petroleum engineering is reported. Also, theoretical and experimental investigations of hysteresis of wettability are compared and discussed in detail. The review highlights a range of concepts in existing models and experimental processes for wettability hysteresis. Furthermore, this paper tracks the current development of hysteresis and provides insight for future trends in the research. Finally, it reveals an outlook on the research challenges and weaknesses of hysteresis of wettability.

The development of offshore heavy oil is sensitive and complex, which is limited by factors such as platform space, economy, pollution and security, so conventional thermal recovery techniques such as cyclic steam stimulation and steam flooding have difficulty in achieving favorable development effect for offshore heavy oil reservoirs. Horizontal-well multi-thermal fluid stimulation (HW-MTFS) process is a relatively new thermal recovery technique, which combines the multiple advantages of gas injection, horizontal well and thermal recovery process. In this paper, the HW-MTFS physical model was firstly designed. Thereafter, the influences of different factors on steam absorption along horizontal wellbore were studied by sand-packed model experiments. Finally, the development performance of horizontal-well cyclic steam stimulation (HW-CSS) process and horizontal-well multi-thermal fluid stimulation process was compared by two groups of physical experiments. The results indicate that different injection factors significantly influenced the steam absorption along horizontal wellbore. Compared with steam injection, the multi-thermal fluid injection could effectively improve the steam absorption along horizontal wellbore. The HW-MTFS process had a higher oil rate and production, and the recovery of HW-MTFS process was 42% higher than that of HW-CSS in three cycles.

In the Chotts zone central part (southern Tunisia), the Jurassic series are interesting for hydrocarbon exploration. However, these series’ composition and geometry are little studied to propose prospection programs. Using boreholes and seismic reflection data, the present study aims a better characterization of the Jurassic series in the Chotts zone central part, in view of petroleum prospects identification. The analysis of the lithological columns and their corresponding well logs highlights an interesting petroleum system: The Tithonian, Kimmeridgian and Oxfordian carbonated deposits are the main reservoirs formations, whereas the Kimmeridgian and Callovian clays constitute the source rocks. The seal rocks are composed of the Jurassic clayey intercalations. Forty-four seismic reflection profiles calibrated using the time–depth relation in petroleum wells are interpreted in this study. The reflectors corresponding to the Malm, Dogger and Lias tops are identified and picked on the different seismic profiles. The isochrone, isobath and isopach maps subsequently deduced disclose important tectonic features that affect the Jurassic series in the Chotts zone and control their geometry. They highlight two sunken zones separated by a raised structure. This structure corresponds to an anticline, overturned toward the south, limited by E–W major faults and truncated by other oriented NW–SE. It constitutes an excellent trap structure where five interesting prospects are precisely delimited. Furthermore, the determined tectonic accidents may facilitate the migration of oil from Jurassic source rocks. The findings of this study can help for better understanding of the Jurassic petroleum system in the Chotts area and guide enormously its exploration.

Invalid PVT data provide high uncertainty in field development studies such as reservoir fluid compartmentalization, reserve estimation, reservoir simulation, production engineering, and surface facility design. Then, consistency check should be conducted to ensure the validity of PVT data and to identify the most representative PVT sample(s). In this paper, preliminary and complementary consistency check of PVT laboratory methods was applied to design a new comprehensive validity check procedure for verification of the reservoir fluid properties. This procedure would be ascertained whether or not the data could be used as the most representative fluid sample in further studies. The data used in this study were collected from seven undersaturated oil reservoirs, and challenges were observed through the 28 full set of available PVT laboratory data. In our study quality checking procedure of PVT samples consists of different methods such as graphical method, recombination and material balance check for well stream composition test, Buckley, modified Wilson and Hoffman plot, Watson characterization factor, Y-function of CCE test, Y-function of DL test, compositional material balance of DL test, overall mass balance for density, Bo and GOR of DL test and density check for separator test. After implementing the applicable proposed checking procedure to detect the validity of laboratory PVT sample, only 9 out of 28 PVT samples were satisfied all the preliminary and complementary check methods. Furthermore, a practical strategy, to select representative reservoir fluid sample, was also provided and discussed based on the consistency check, well condition check and comparison of fluid properties.

A potential biosurfactant producing isolate was identified as Bacillus aryabhattai strain ZDY2. Biosurfactant production was enhanced by 2.51-fold through the development of an optimized process using response surface methodology. The optimized culture medium contained crude oil 4.0%, yeast extract 0.7% and NaNO3 3.0% that yielded 8.86 g/l of biosurfactant. Biosurfactant was characterized for stability up to 100 °C, at pH 5–10 and in the presence of NaCl concentration up to 8%. Biosurfactant demonstrated antimicrobial activity against Salmonella typhimurium, Escherichia coli, Micrococcus luteus, Staphylococcus aureus and Candida tropicalis. The morphological characterization was carried out by scanning electron microscopy with energy-dispersive X-ray analysis. The Fourier-transform infrared spectroscopy analysis reveals the lipopeptide nature of the biosurfactant produced by B. aryabhattai strain ZDY2. The biosurfactant finds application in healthcare and pharmaceutical industries.

Sonic well logs provide a cost-effective and efficient non-destructive tool for continuous dynamic evaluation of reservoir formations. In the exploration and production of oil and gas reservoirs, these sonic logs contain crucial information about the formation. However, shear sonic logs are not acquired in all oil and gas exploration wells. More so, many offset wells are not run with the most recent sonic logging tools capable of measuring both shear and compressional sonic transit times due to the relatively high costs of running such equipment. And in wells where they are deployed, they are run only over limited intervals of the formation. Such wells lack continuous shear wave transit time measurements along the formation. In this study, an exponential Gaussian process model is presented. The model accurately predicts the shear wave transit times in the formations which lack reliable shear wave transit time measurements. The proposed model is developed using an array of well logs, namely depth, density, porosity, gamma ray, and compressional transit time. A Monte Carlo simulation is used to quantify the proposed model uncertainty. The shear sonic transit time predictions are used to estimate some formation deformation properties, namely Young’s modulus and Poisson’s ratio of a reservoir formation. The results suggest that shear transit time can be represented and predicted by Gaussian-based process model with RMSE, R2, and MSE of 11.147, 0.99, and 124.6, respectively. The proposed model provides a reliable and cost-effective tool for oil and gas dynamic formation evaluation. The findings from this study can help for better understanding of shear transit times in formations which do not have multipole sonic logs or where data have been corrupted while logging in the Niger Delta.

Water injection technique is contributing millions of oil barrels on a daily basis to the global oil supply; one of the challenges faced by such an important production method is scale buildup due to the different dissolved solids and high salinity of the injected water. For produced water or effluent water, pretreatment is a critical step before the injection process to reduce the risk of scale potential and well formation damage. One of the beneficial treatments of the effluent water is to be mixed in a compatible ratio with seawater, especially for those countries with easy access to seawater. Thus, the objective is to find a compatible mix ratio with seawater as one way of solving effluent water reuse without increasing the risk of scale and formation damage during water injection operation. In this study, effluent water samples were collected from different oilfield geographical locations in Kuwait, and then the samples were analyzed in the laboratory for their physical and chemical properties to select the most compatible one for mixing with seawater. The selected effluent water was then mixed with seawater in 1:1 ratio to evaluate the compatibility of the mix in terms of sulfate formation and scale tendency. The selected North field/seawater was tested under 75 ºC and 1000 PSi in an autoclave. The filtered precipitates were characterized by energy-dispersive spectroscopy (EDS) and scanning electronic microscope (SEM) micrographs. Further, the formations of sulfate were detected by X-ray diffraction (XRD). The OLI ScaleChem software was used to investigate the composition of mineral scales that may occur in the water mix at different ratios ranging from 0 to 100% to compare it with the actual water mix finding. In the effluent waters comparison part, North field water showed low pH (4.6) and alkalinity, as well as moderate TDS (190,000 MG/L). The main constituents of the scale deposited at the selected water mixing ratio were calcium sulfate CaSO4 and silicon oxide detected by XRD. However, the amount of barium sulfate was not presented in the precipitates indicating that all of it went in the liquid phase. The study concludes that at downhole conditions, the compatible mix of North Kuwait effluent water with seawater has high risk of barium sulfate in comparison with other common scale such as calcium sulfate, calcium carbonate and strontium sulfate (SrSO4). Also the study revealed that the prediction of different seawater ratios showed that at 70% seawater concentration, the barium sulfate concentration drops and consequently the scale risk reduced.

Oil sands are characterized by shallow burial and extremely high viscosity, whose exploration technologies and production methods are quite different from that of conventional oil and gas. Oil sands with the largest reserve scale and best quality in China are developed in Fengcheng area of Junggar Basin. This paper presents the forming conditions and enrichment rules of oil sands in Fengcheng area. The dividing standards for effective thickness of oil sands are established with exploration technologies like high-density drilling, whole well section coring and the method of weight percentage of bitumen. The geologic reserves of oil sands are calculated with the method of weight percentage of bitumen. Open-pit mining practices and SAGD double horizontal well development tests are carried out, and good effects are obtained in SAGD production. At present, Fengcheng oil sands have been developed on a large scale with SAGD technology.

This study investigates different types of waste materials and their applicability in the oil and gas industry as well as analyzing various applications of these waste materials in the petroleum industry. This study also explores the availability of these waste materials by performing a statistical analysis in a good number of countries worldwide. The statistical study was performed starting with a study on which countries generate waste the most overall, followed by examining multiple countries and investigating their top three most available waste. The results showed that the USA is the leading country in terms of municipal solid waste generation of 258 million metric tons, followed by China that generates around 220.4 million metric tons and then India that generates 168.4 million metric tons of municipal solid waste. The regions that generate the most food waste are North America and Oceania, providing the availability of food waste in those regions. Most of the palm tree wastes are available in the Middle East and some parts of the USA, while green waste can be found in the USA, China, and the UK. Sawdust wastes are mostly available in Europe and North America, while hay waste is abundant in the USA. Waste materials were also examined for various petroleum industry applications. Food wastes were found to be effective in drilling and completion fluids. Various food waste products were utilized to alter the drilling fluid properties such as potato peels and mandarin peels. Food wastes were also effective in altering the pH of the drilling fluids. Some plant-based wastes such as date trees were effective treatments used to stop lost circulation. Based on biodegradability and toxicity basis, waste materials were also classified into four main categories, which are eco-friendly, biodegradable, non-biodegradable, and toxic using color category classification. In summary, waste materials have the potential to be used in the petroleum industry, and they might as well be a good alternative for the future. As an example, the drilling fluid average cost approximately one-tenth of the total cost of the drilling operation, which is considered a tangible cost. By using waste materials as drilling fluid additives, the cost of the drilling fluid can be minimized. Further investigation and research should be carried out to get a better understanding of the importance of waste materials, and how they can be exploited for future applications in the oil and gas industry.

Developing a reliable classification model for drilling pipe stuck is crucial for decision-makers in the petroleum drilling rig. Artificial intelligence (AI) includes several machine learning (ML) algorithms that are used for efficient predictive analytics, optimization, and decision making. Therefore, a comparison analysis for ML models is required to guide practitioners for the appropriate predictive model. Twelve ML techniques are used for drilling pipe stuck such as artificial neural networks, logistic regression, and ensemble methods such as scalable boosting trees and random forest. The drilling cases of the Gulf of Suez wells are collected as an actual dataset for analyzing the ML performance. The key contribution of the study is to automate pipe stuck classification using ML algorithms and mitigate the pipe stuck cases using the genetic algorithm optimization. Out of 12 AI techniques, the results presented that the most reliable algorithm was extremely randomized trees (extra trees) with 100% classification accuracy based on testing dataset. Moreover, this research presents a public open dataset for the drilled wells at the Gulf of Suez to be used for the future experiments, algorithms’ validation, and analysis.

The pressure response during a well test provides important information about reservoir properties, well productivity or reservoir performance. In order to have an option to replace traditional production tests, avoiding the gas flaring and increasing operational safety, injectivity test began to play an important role in the management of reservoirs. Although analytical models are able to describe injection and falloff periods, multiple rate models still need to be developed. This work presents a new formulation to compute pressure response when performing multiple rate injectivity test in a water injection well operating in an oil zone. First, the proposed formulation is compared to injection/falloff models and after a multiple rate scheme is performed. This formulation extends prior models presented in the literature. The accuracy of the proposed solution was assessed by comparison with a numerical simulator. The proposed formulation is also used to determine the reservoir equivalent permeability in any specific period of injection or shut-in.

Immiscible carbon dioxide (CO2) injection is one of the highly applied enhanced oil recovery (EOR) methods due to its high oil recovery potential and its ability to store CO2 in the reservoir. The main mechanism of immiscible CO2 injection is oil swelling. Generally, oil swelling is measured experimentally or measured using modeling methods. This research conducts oil swelling experiments using a simplified method in order to easily and accurately measure oil swelling and determines some of the most significant factors that may impact oil swelling during CO2 injection. The impact of varying CO2 injection pressure, temperature, oil viscosity and oil volume on oil swelling capacity was investigated. The simplified method managed to accurately determine the value of oil swelling for all the experiments. One of the factors that was found to impact the method significantly was the oil volume used. The oil volume in the experimental vessel was found to be extremely important since a large oil volume may result in a false oil swelling value. The oil swelling results were compared to other researches and showed that the method applied had an accuracy of over 90% for all the results obtained. This research introduces a simple method that can be used to measure oil swelling and applies this method to investigate some of the factors that may impact the oil swelling capacity during immiscible CO2 injection.

Based on a sum of well test interpretation analysis, the flowage characteristics of the gas in reservoir were analyzed from physical parameters and double-logarithm curve characteristics of gas wells. The result showed that the permeability of gas well-fracturing area is greatly improved, which is the main area to provide productivity. The speed of pressure transmission was slow because of extremely low permeability of outside the fracturing area and fluid flow was dominated by a linear flow. And three common well test interpretation models were extracted. The characteristics of bi-zonal compound reservoir of gas wells were specified by combination with peripheral supply and pressure change characteristics of gas wells. Variations of reservoir pressure and flowing bottom-hole pressure with time were simulated and quantified under different physical parameters and daily production. And the rational proration scheme of gas production wells was established by integration with numerical simulation method. Numerical simulation results of 21 sets of well patterns showed that there were two recovery inflection points. And a new model was built to research well interference degree that was defined by a new and original mathematical expression about production. The result showed that the infill well pattern should be controlled at 500 m × (500–600) m.

This paper addresses the probabilistic analysis of casing tubulars, regarding the failure modes defined in API 5C3 code, which refers to the violation of elastic regime due to internal and external pressures, and axial force. The casing system performs important structural and isolation functions, ensuring the well integrity through its life cycle. The reliability-based casing design handles rigorously the uncertainties associated with the tube manufacturing, as variations in geometrical and mechanical properties, allowing to evaluate the probability of failure. It is presented a parametric analysis over different steel grades and tube slenderness, besides the application to a design scenario, by using Monte Carlo simulation and first-order reliability method. The results indicate that: collapse is the dominant failure mode; wall thickness and the yield limit govern the probabilistic response; the triaxial envelopes, revisited in a probabilistic framework, consist in a powerful tool, supporting the decision-making process in casing design.

Relative permeability (kr) and the capillary pressure (Pc) are the central key elements defining the multiphase fluids flow behavior in the porous media. However, the dynamic capillarity should consider the dynamic relative permeability and the dynamic capillary pressure while performing waterflooding process in extremely low permeable formations. In order to improve the oil production, the advanced horizontal well drilling along with multiple hydraulic fracturing is generally instigated to penetrate the unconventional resources. The aim of this study is to consider the dynamic capillarity in a commercial reservoir simulation, while utilizing the data gained from the dynamic and steady experiments of the relative permeability and the capillary pressure impacts during waterflooding process in the core plugs of unconventional tight oil reservoirs. The commercial reservoir simulation conducted sensitivity analyses using Computer Modeling Group simulator. The outcomes show that the well production of the reservoir is overestimated while implementing steady data for forecasting due to which the oil saturation decreases more equally and further rapidly. Additionally, the forecast of the well production estimated to breakthrough sooner. However, neglecting the dynamic capillarity causes a huge breakthrough of water influx. Therefore, the core objective of this study is to probe the consequences of taking into consideration the dynamic capillarity in ultra-low permeable formations while giving an alternative perspective to forecast the production of the hydraulically fractured unconventional tight oil reservoirs.

Produced water handling has become one of the central concerns for the oil and gas industry today. Produce water (water cut) increases as the field grows old, which brings the additional handling cost to the project. The additional expense could be in terms of lifting cost, treatment, maintenance, tubular scaling, corrosion problems, bacteria, naturally occurring radioactive material and environmental regulations, etc. To address this problem, the hydrocarbon industry developed the downhole oil–water separation (DOWS) technology in the 1990s. In spite of having such cost-effective and environment-friendly solutions, the industry has limited sites using this technique. Thus, there is uttermost need to evaluate the problems in practicality of the current hydrocyclone-based and gravity-based DOWS and find a reliable solution to it. The membrane-based separation methodology represents the coherent solution to robust the downhole separation system that does not require any moveable equipment with advance sensors and mechanical tools. If the reservoir is well characterized and a reliable simulation model is built, it is possible to predict the optimal time for the placement of a specific length of membrane in the well depending on the layer concerned and inclination of the well. Apart from designing the thin and porous hydrophobic and oleophilic membranes, there are plenty of field challenges which have put constraints on the practicality of membrane-based DOWS. The major constraints are durable range of separation pressure, fouling, separation process design, membrane-shear durability. The objective of this study is to present a novel model of PTFE (polytetrafluoroethylene) membrane-based downhole oil–water separation system with its over all functionality and addresses the constraints mentioned above with promising existing working solutions. Moreover, the study also literature reviews and compares the expenditure and maintenance involved in manufacturing, installation, operating and maintenance of system, between the conventional hydrocyclone-based downhole water separation and the proposed (PTFE) membrane-based DOWS.

Bottom-hole flowing pressure and pump intake pressure (PIP) are important parameters to optimize the performance of oil wells. In recent years, downhole sensors are becoming widely used in electrical submersible pump systems to measure these pressures. However, it is still rare to use downhole sensors in sucker rod and progressive cavity pumped wells. In this study, two correlations were developed to calculate bottom-hole flowing pressure and PIP from readily available field data. The two correlations do not require measurements of buildup tests, but they rely on measuring the dynamic fluid level and estimating fluid gradient correction factor using either (1) the tubing gas flow rate or (2) the annular gas flow rate. Then, the PIP is calculated by the summation of either (1) the tubing pressure plus the tubing gaseous liquid column pressure or (2) the casing pressure, annular gas column pressure and the annular gaseous liquid column pressure. The correlations were developed using 419 field data points (389 points for training and 30 for testing) of wide range for each input parameter. Using the training data, the mean absolute percentage deviation (MAPD) between the calculated and measured PIPs is 25% and 20% for the first and second correlations, respectively. However, the testing data showed MAPD of 33% and 12% for the first and second correlations, respectively. The accuracy of these correlations is significantly higher than that of the previously available methods, and the correlations require simpler input. Such study is an original contribution to calculate the PIP with improved accuracy and without downhole pressures sensors.

Waterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.

Hydrolyzed polyacrylamide polymer (HPAM) is the most used polymer in enhanced oil recovery operations in the oil industry. This is mainly attributed to its cost and availability. An important aspect during polymer injection in the formation for mobility control is the ability to inject the polymer easily and safely in the reservoir without having to deal with extremely high pressure gradients and without risking formation fracture. This research develops two mathematical models that can help obtain values for polymer injectivity as a function of HPAM concentration, injection flowrate, and the porous media pore size. The mathematical models were developed based on experiments conducted previously using different polymer concentrations, pore sizes, and polymer injection flowrates. After the models were developed, different data were used to validate the model and examine its accuracy in determining polymer injectivity. The models were also used to predict polymer injectivity for different conditions and illustrate the pore sizes at which the polymer was not able to propagate in the formation. Since the models have several limitations, these were mentioned in the manuscript in order to reduce any error obtained while using the models.

Oil recovery in oil rim reservoirs is usually affected by reservoir and operational parameters. An experiment was designed to develop various types of oil rims with a broader range of uncertainties. Mensuration analysis was used to create the basic grid designs, while the Eclipse software was used to incorporate pressure, volume and temperature and reservoir fluid properties to create a black oil model for oil rims. The reservoir models were conditioned to a simultaneous production scheme through which a response surface model was generated to represent oil recovery for all the models. The models were later classified into drive mechanisms based on the results from the Pareto analysis. Various secondary injection schemes were carried out based on reservoir geometry to investigate their response on oil recovery. Results show that for single injection schemes, oil recovery from water down-dip (6.5%) and water up-dip (4.37%) was higher than gas scheme injection for reservoir model 10. Oil recovered from up-dip and down-dip water injection (7.1%) was higher than gas up-dip and down-dip injection (0.03%) for reservoir model 10, and for the same model, an oil recovery of 7.7% and 5.63% was recorded for gas up-dip and water down-dip injection and gas down-dip and water up-dip injection, respectively. The final analysis shows that there is an appreciable increase in oil recovery when injection rates are increased as seen in water down-dip and up-dip injection with 15.43% recovery for reservoir model 10.

An integrated structural and stratigraphic analysis of a regional dataset from Eastern Niger Delta was undertaken with the objective of improving the present understanding of the structural development, seismic reflection geometries and implication on sand transportation and deposition within the shelf-edge and farther into the basin floor. Well log correlations were carried out using third-order sequence stratigraphy. Fault dynamics and evolution was interpreted with the aid of seismic transect sections, growth fault indexes and dip-extracted semblance slices. Lithofacies and paleobathymetric data were utilized to create gross depositional environment maps for the various sequences from inner-shelf to upper slope environment. The fault dynamics and evolution analysis of co-planar faults shows that older co-planar faults are associated with more accommodation space and depocentres than relatively younger faults. Conceptual subsurface models from this study shows that there is an increase in sand thickness in the proximal part of the sequence associated with precursor (older) faults, while towards the distal part, it reduces. There is also a relative decrease in sand thickness in the proximal part of the sequence associated with younger initiated faults, while towards the distal part, it increases in sand thickness. This study shows that at the shelf-edge, the thickest sand is of the lowstand system tract and the possibility of transporting sands into the basin is more associated with younger co-planar faults with small accommodation space at the shelf-edge, while the precursor older faults retain majority of sand deposits within its subsidence/depocentre axis.

Coal seams, particularly deep unmineable coal reservoirs, are the most important geological desirable formations to store CO2 for mitigating the emissions of greenhouse gas. An advantage of this process is that a huge quantity of CO2 can be sequestrated and stored at relatively low pressure, which will reduce the amount of storage cost required for creating additional platform to store it. The study on CO2 storage in coal seam to enhance coal bed methane (ECBM) recovery has drawn a lot of attention for its worldwide suitability and acceptability and has been conducted since two decades in many coalmines. This article focuses on the coal seam properties related to CO2 adsorption/desorption, coal swelling/shrinkage, diffusion, porosity and permeability changes, thermodynamic/thermochemical process, flue gas injection, etc. Here, the performance analysis of both CO2 storage and ECBM recovery process in coal matrixes is investigated based on the numerical simulation. In this study, a one-dimensional mathematical model of defining mass balances is used to interpret the gas flow and the gas sorption and describe a geomechanical relationship for determining the porosity and the permeability alteration at the time of gas injection. Vital insights are inspected by considering the relevant gas flow dynamics during the displacement and the influences of coal swelling and shrinkage on the ECBM operation. In particular, pure CO2 causes more displacement that is more efficient in terms of total CH4 recovery, whereas the addition of N2 to the mixture assists to make quicker way of the initial methane recovery. However, this study will support future research aspirants working on the same topic by providing a clear conception and limitation about this study.

Estimating the contact angle in very complex rock pores presents some challenges to accurately identify the fluid–rock contact surface. This work presents a methodology to estimate the contact angle formed by the brine–rock and the brine–oil interfaces on processing high-resolution images provided by micro-CT scan. We focus the discussion on the limitations of the most popular computational techniques used to determine the contact angle and discuss how to select a practical way to evaluate it. The method consists of four steps: (1) processing the images to determine each fluid present in the image, (2) selection of the pixels that will be part of the contact interface of fluids and the contact point, (3) fitting polynomial equations for each interface and selection of the equation that gives the lowest error, (4) estimation of the contact angle based on the more appropriate polynomial equation. The contact angle is calculated based on the slope of the interfaces’ tangents at the contact point. Several types of approaches were tested to determine the contact interface and the contact point. In order to evaluate the applicability of our method, we use an analytically generated image and rock sample images. Potential errors between the angle obtained from the analytically generated image and the angle calculated from the method show the impact of the right selection of pixels during the image processing step. High sensitivity is also observed for the tangent values in the presence or absence of pixels from the rock sample analysis.

Mudstone reservoirs demand accurate information about subsurface lithofacies for field development and production. Normally, quantitative lithofacies modeling is performed using well logs data to identify subsurface lithofacies. Well logs data, recorded from these unconventional mudstone formations, are complex in nature. Therefore, identification of lithofacies, using conventional interpretation techniques, is a challenging task. Several data-driven machine learning models have been proposed in the literature to recognize mudstone lithofacies. Recently, heterogeneous ensemble methods (HEMs) have emerged as robust, more reliable and accurate intelligent techniques for solving pattern recognition problems. In this paper, two HEMs, namely voting and stacking, ensembles have been applied for the quantitative modeling of mudstone lithofacies using Kansas oil-field data. The prediction performance of HEMs is also compared with four state-of-the-art classifiers, namely support vector machine, multilayer perceptron, gradient boosting, and random forest. Moreover, the contribution of each well logs on the prediction performance of classifiers has been analyzed using the Relief algorithm. Further, validation curve and grid search techniques have also been applied to obtain valid search ranges and optimum values for HEM parameters. The comparison of the test results confirms the superiority of stacking ensemble over all the above-mentioned paradigms applied in the paper for lithofacies modeling. This research work is specially designed to evaluate worst- to best-case scenarios in lithofacies modeling. Prediction accuracy of individual facies has also been determined, and maximum overall prediction accuracy is obtained using stacking ensemble.

The increasing energy demand has to be met while we transitioned to a decarbonized energy future. Heavy oil and bitumen reserves are urgently needed to be developed to ensure that a smooth transition is provided. In this work, field-scale kinetics parameters are used to study the effect of reservoir pay thickness on the performance of toe-to-heel air injection (THAI) process. Air was injected at constant rate into three different models with the thicknesses of 24 m, 16 m, and 8 m, respectively. The oil produced is slightly affected by the reservoir thickness. It is found that the lower the reservoir thickness, the larger the cumulative air-to-oil ratio (cAOR), indicating that heat loss increases with the decrease in the reservoir thickness. This trend is similar to steam-based processes. At constant air injection flux, it is found that both the cumulative oil produced and the cAOR decrease with the decrease in the reservoir thicknesses. This decrease is attributed to the decrease in the rate of heat generation in the thinner reservoirs, which in turn results in lower combustion zone temperature and thus lower temperature gradients between the reservoir and the overburden and the reservoir and the underburden. Consequently, a more general conclusion is that decreasing the air injection rate by the same factor the reservoir thickness is decreased (i.e. keeping the air injection flux constant) results in a more economical THAI process operation compared to when the air injection rate is kept constant (i.e. allowing increase in air injection flux).

Xanthan gum is commonly used in drilling fluids to provide viscosity, solid suspension, and fluid-loss control. However, it is sensitive to high temperatures and not tolerant of field contaminants. This paper presents an experimental study on the effects of an eco-friendly biopolymer (diutan gum) on xanthan gum (XC) in a water-based bentonite mud. Laboratory experiments were carried out for different compositions of the biopolymers in water-based bentonite muds formulated without salt and in water-based bentonite muds containing sodium chloride (NaCl). The rheological properties of the water-based bentonite muds formulated with XC (2 Ibm) and those of the water-based bentonite muds prepared using XC (1Ibm) and diutan gum (1Ibm) were measured using Model 1100 viscometer after aging at 25 °C, 100 °C, and 120 °C for 16 h. The API fluid loss and filter cake of the mud formulations were measured using HTHP filter press. The properties of the water-based bentonite muds containing only XC were compared with those of the water-based bentonite muds containing XC and diutan gum. Presented results show that combining diutan gum and xanthan gum in a ratio of 1:1 in a water-based bentonite mud enhances its performance with respect to fluid properties—apparent viscosity, gel strength, yield points, YP/PV ratio, LSRV,n, andK. The fluid formulations also showed favorable mud cake building characteristics. Experimental data also indicate a 16%, 19%, and 34% reduction in API fluid loss values for the water-based benitoite muds containing XC in the presence of diutan gum after aging at 25 °C, 100 °C, and 120 °C for 16 h, respectively. Experimental results also show that the water-based benitoite mud containing XC and diutan gum would cause less formation damage and was tolerant of contamination with a monovalent cation (Na+). The synergy of xanthan gum and diutan gum can, therefore, improve the performance of water-based drilling fluids.

CO2 flooding has become one of most effective methods to improve oil recovery in low-permeability reservoirs. Thus, influencing factors have been specifically analyzed for their impact on oil displacement. Factors that are difficult to observe, such as capillary pressure and CO2 dissolution, have often been neglected in specific analysis. To do so, this paper combined laboratory experimentation with numerical simulation analysis to understand the specific functions of capillary pressure and CO2 dissolution in the CO2-flooding process in low-permeability reservoirs. Based on laboratory experiments with long cores applying different CO2-flooding methods, the authors established a one-dimensional numerical simulation model for CO2 flooding. After that, the model was simulated to analyze the effects of capillary pressure and CO2 dissolution for different CO2-flooding processes. The results show that the function of capillary pressure in different CO2-flooding modes is not consistent in low-permeability reservoirs; furthermore, capillary pressure is a driving force in the process of flooding and is a resistance force in the CO2-flooding process after pressure recovery. When considering CO2 dissolution in different flooding modes, its function was shown to be inconsistent in low-permeability reservoirs compared with CO2 flooding without considering CO2 dissolution; oil recovery is reduced in the CO2-flooding process, but oil recovery increases in the CO2-flooding process after pressure recovery. Therefore, in order to promote the rational and effective development of low-permeability reservoirs, it is necessary to understand the functions of capillary pressure and CO2 dissolution clearly in the process of CO2 flooding.

Over the time by increasing global demand for source of energy and decreasing hydrocarbon production from reservoirs, recovery methods have become important. The surface area and porosity are central physical characteristics that highly affect the estimation of original oil and gas in place and understanding the mechanisms incorporating in production. The surface area is the internal surface area per unit of pore volume and determines the amount of space in rocks exposed to injectant during injection operation. The occurrence of fractures system in carbonated reservoirs increases the complexity and decreases the homogeneity; hence, it is difficult to determine the correct surface area of reservoir. Therefore, the existence of a local correlation which relates effective porosity to specific surface area is needed and it can help to estimate effective surface area exposed to chemicals during Enhanced Oil Recovery (EOR) process. In this study, the specific surface area in carbonate reservoir rocks was measured by gas adsorption (nitrogen) method and petro-graphical image analysis. In addition, the effective porosity was determined by a gas porosimeter, followed by plotting specific surface area measured by the Brunauer, Emmett and Teller (BET) method versus specific surface area determined from core scan and calibration curve. According to this calibration curve, a new relationship was developed (with R2 = 0.92) that could give BET data for a known data of core scan. The relationship between porosity and specific surface area was analyzed statistically and a relationship with accuracy of R2 = 0.89 was proposed. This relationship was compared with other models such as Pirson and Kotyakhov. Results show that the latter one is more accurate than other models and is more compatible with experimental data (with R2 = 0.84). The results obtained from the experiment indicate that the specific surface area shows an initial decrease upon increasing of porosity up to 0.2. After this decrease, the curve indicates an increasing trend. Moreover, a novel relationship was developed depending on the specific surface area, porosity and permeability and some constant parameters for carbonate rocks (with R2 = 0.95).

The tight reservoirs in Dagang Oilfield are deep in burial depth and complex in lithology, and the brittleness evaluation methods commonly used at home and abroad are not accurate enough to effectively guide the design of fracturing. As a result, the fracturing in the early days was low in success rate and not ideal in effect. In this study, from the perspective of breaking energy theory, based on a large number of core experiments, the factors affecting rock failure morphology have been analysed by using the breaking energy theory, and a brittleness evaluation method more suitable for the physical properties of tight reservoirs in Dagang Oilfield has been worked out. The results show that the main parameters affecting brittleness of tight reservoirs in Dagang Oilfield are Young’s modulus, dilatancy angle and peak strain. The correlation coefficient between the brittle index from the new method based on breaking energy theory and rock failure complexity increases to 0.789 compared with 0.329 of the brittle index from Rickman’s evaluation method. The new method solves the problem that previous brittleness index models at home and abroad are not suitable for tight reservoirs in Dagang Oilfield, and provides a theoretical basis for evaluating the fracability of tight reservoirs and improving fracturing effect in Dagang Oilfield.

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).

An energy-saving water injection pump aimed at high-energy consumption and low efficiency of the traditional water injection pump in the later stages of oilfield exploitation is proposed. The hydraulic pump is used as the main power source to control the movement of the piston through the mechanical reversing valve, thereby driving the plunger to move left and right, supercharging the water in the plunger cylinder. First, the structural parameters of the energy-saving water injection pump were determined. Then, dynamic analysis of the pump parts was carried out. The finite element simulation of the piston cylinder and the plunger cylinder showed that the structural strength meets the requirements. The hydraulic system dynamic simulation showed that the output pressure can reach the predetermined pressure. Finally, a field test was carried out in the Jiangsu Oilfield. The results show that the device can meet the water injection requirements of the oilfield.

The basic architecture of reservoir models is heavily impacted by the stratigraphic interpretation. The estimation of in-place hydrocarbon volumes and recoverable hydrocarbon volumes will rely on the accuracy of predicting and distributing reservoir quality away from well control. In this paper the interpretation of sedimentological and stratigraphic analyses is used to define reservoir geometry, lateral continuity and determine technique needed for 3D static modelling. The objective of this study is to use a sequence stratigraphic framework and depositional model to predict the characteristic fabric of X1 and X2 reservoirs in unknown portions of the field. Log motifs from four wells (Koca-01, Koca-02, Koca-03 and Koca-04) and core report from a nearby well Z07 were used to classify facies types. Biostratigraphy data from Koca-01 were used to identify key stratigraphic markers. A sequence stratigraphic framework of the facies was built and correlated across the field. This interpretation was further used to build a conceptual depositional model that best represented the environment of deposition for these reservoirs. Results show the major facies associations as distributary channels and shoreface sands. X1 and X2 reservoirs are interpreted to be progradational sands within a highstand system tract. Correlation shows good sand connectivity and distribution of gross reservoir thickness in 2D. The depositional model in this paper was used in 3D static models to improve geometric characterization in 3D static modelling.

Polymer flooding has been established as an effective enhanced oil recovery (EOR) technique and can be utilized in large-scale field expansions. With high success rates and efficiency, polymer flooding operates by increasing the viscosity of water, promoting greater sweep efficiency and resulting in higher oil recovery beyond conventional waterflooding. Predicting viscosity has been established by numerous researchers as an essential tool to study polymers behavior under varying conditions. Previous model has proven a link between polymer viscosity and zero shear rate viscosity, relaxation time, hardness, and many other factors. This research initially reviews different types of polymers that can be applied successfully in EOR, demonstrate conditions that can alter polymer viscosity in porous medium, and analyze models that predict polymer bulk and in situ viscosity. The research then discusses a novel modification of the power law model to predict HPAM (SAV10) viscosity in a wide range of shear rates based on polymer concentration, fluid salinity, and divalent content. A polymer rheology study was carried out on SAV10 at various concentrations (750–5000 ppm) and brine salinities (43–210 k ppm). Results show the effectiveness of the model and the ability to predict viscosity accurately in low to medium shear rates, while in high shear rate, a slight deviation was noticeable.

This study is intended to expand the scope of microbial enhanced oil recovery (MEOR) simulation studies from 1D to field scale focussing on fluid viscosity variation and heterogeneity that lacks in most MEOR studies. Hence, we developed a model that incorporates: (1) reservoir simulation of microbe-induced oil viscosity reduction and (2) field-scale simulation and robust geological uncertainty workflow considering the influence of well placement. Sequential Gaussian simulation, co-kriging and artificial neural network were used for the petrophysical modelling prior to field-scale modelling. As per this study, the water viscosity increased from 0.5 to 1.72 cP after the microbe growth and increased biomass/biofilm. Also, we investigated the effect of the various component compositions and reaction frequencies on the oil viscosity and possibly oil recovery. For instance, the fraction of the initial CO2in the oil phase (originally in the reservoir) was varied from 0.000148 to 0.005 to promote the reactions, and more light components were produced. It can be observed that the viscosity of oil reduced considerably after 90 days of MEOR operation from an initial 7.1–7.07 cP and 6.40 cP, respectively. Also, assessing the pre- and post-MEOR oil production rate, we witnessed two main typical MEOR field responses: sweeping effect and radial colonization occurring at the start and tail end of the MEOR process, respectively. MEOR oil recovery factors varied from 28.2 to 44.9% OOIP for the various 200 realizations. Since the well placement was the same for all realizations, the difference in the permeability distribution amongst the realizations affected the microbes’ transport and subsequent interaction with nutrient during injection and transport.

Most of drilling hole problems are attributed to wellbore stability issues which adversely cause excessive lost time and cost millions of dollars. The past drilling experiences in Kupal oilfield showed excessive mud losses, kick flows, tight holes and pipe stuck leading to repeated reaming, fishing and sidetracking. Most of the drilling-associated problems in this field occurred during drilling the 12 ¼-in. hole, which is across the non-reservoir Gachsaran formation (consisting of anhydrite, gypsum and marl with thin limestone layers). Mainly due to the lack of required formation evaluation data, no geomechanical studies of this formation have been conducted to date. In this work, first, we constructed a geomechanical model to investigate the root of the problems. This is a pioneer wellbore stability work for such a complex lithology formation which included finding the equations best-matching with core data and field observations. Finally, to overcome the field challenges and hole problems, the study proposes some field remedial actions. The results of the geomechanical modeling show that the pore pressure, shear and tensile failure gradients are greatly variable with the safe mud weight window becoming excessively narrow at some intervals. This accounts for the encountered wellbore stability issues as managing the mud weight in these situations requires several casing strings. To mitigate the extent of the problem, this study proposes the application of innovative drilling technologies including casing while drilling to eliminate the casing running time with potential reduction in drilling time, and continuous circulation system to prevent cuttings settling and kick flows during connections. These technologies are capable of elimination of the geomechanical part of the drilling delay (30% of the average 77 drilling days) per well.