Uncovering the reaction mechanism behind CoO as active phase for CO2 hydrogenation

Transforming carbon dioxide into valuable chemicals and fuels, is a promising tool for environmental and industrial purposes. Here, we present catalysts comprising of cobalt (oxide) nanoparticles stabilized on various support oxides for hydrocarbon production from carbon dioxide. We demonstrate that the activity and selectivity can be tuned by selection of the support oxide and cobalt oxidation state. Modulated excitation (ME) diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS) reveals that cobalt oxide catalysts follows the hydrogen-assisted pathway, whereas metallic cobalt catalysts mainly follows the direct dissociation pathway. Contrary to the commonly considered metallic active phase of cobalt-based catalysts, cobalt oxide on titania support is the most active catalyst in this study and produces 11% C2+ hydrocarbons. The C2+ selectivity increases to 39% (yielding 104 mmol h−1 gcat−1 C2+ hydrocarbons) upon co-feeding CO and CO2 at a ratio of 1:2 at 250 °C and 20 bar, thus outperforming the majority of typical cobalt-based catalysts.

A State-of-the-Art Approach to Unlock the Potential of Complex Sour Reservoirs in Southern Oman During Global Market Downturn

Recent years and especially the coronavirus pandemic have been very challenging for the oil industry, resulting in a significant reduction in investment, forcing companies to review budgets and search for more efficient and economical technologies to achieve the target level of hydrocarbon production and revenue generation. In PDO, one of the most challenging fields is "AS", where extreme downhole conditions require a very well-engineered approach to become economical. This field has already seen some of the most advanced technology trials in PDO that are also covered in multiple SPE papers. Based on the new approaches and techniques that were successfully implemented on recently drilled wells, it was decided to review the older, previously fractured wells in the area and assess them for a refracturing opportunity. The main challenge in this project was that these older wells were previously hydraulically fractured in multiple target intervals, therefore both zonal isolation and successful placement of the new fracs were becoming the major concerns. As the planned coverage by the new fractures was to ensure no bypassed pay, the only applicable technology on the market was a pinpoint fracturing process, whereby the targeted placement is achieved through limited entry perforations and focused energy of the injected fluid. The subject pinpoint technology anticipates that the limited entry sandblasting perforation is created and then proppant laden fluid is pumped through a sandblasting nozzle which is part of either a coiled tubing (CT) or a jointed pipe (JP) Bottom Hole Assembly (BHA), and the backside (or the annulus of the injection path) is used to maintain the positive backpressure from the top. This technology allows for choosing a desirable order of target interval selection inside the well, unlike conventional plug and perf or a simplified multistage completion, where the treatments must be placed only in order from bottom to top. Another advantage of this approach is a faster frac cycle through the elimination of wellbore cleanout requirement. Being a unique and first-ever application in the Middle East, using CT for placing frac treatments through a jetting nozzle demonstrates the full scale potential of this approach not only in conventional wells but also in complex, sour and High Pressure (HP) environments that are often found in the Sultanate of Oman and in the Middle East. This paper will cover the advantages and disadvantages, complexity and requirements, opportunities and lessons learnt in relation to this approach.

Risk decreasing of water waste through spontaneous fracturing in injectors by integrated well-testing and production logging

Background. When creating an effective reservoir pressure maintenance system, unstable spontaneous hydraulic fractures can be created in injection wells. This can both negatively and positively affect hydrocarbon production. First, fracture improves reservoir connectivity, which increases injection efficiency. On the other hand, unstable fractures can cause behind-the-casing flows and unproductive injection into off-target layers or fingering. Goal. The paper is devoted to the analysis of well testing (PTA) and production logging (PLT) improvement for the diagnosis of unstable fractures in injection wells. Materials and methods. The analysis is based on the results of modeling the pressure in the reservoir system, describing the penetration reservoirs by an unrestricted conductivity unstable fracture. It is taken into account that the fracture can cross both the perforated formation and the thickness not penetrated by the perforation, and can grow with increasing overbalance. The modeling results made it possible both to assess the potential informative capabilities of well testing and to substantiate recommendations for the practical use of the obtained results. Conclusions. The proposed approaches to the technology of well testing and production logging and the interpretation of their results make it possible to estimate the additional thicknesses of the reservoirs connected by the spontaneous hydraulic fracturing to injection, the proportion of nonproductive injection in the total volume of the well. The research technology used by the authors is based on continuous measurements of pressure and flow rate during cyclic change of pressure and assessment of the effective transmissibility of the formation system at different heights of unstable fractures. The role of the PLT is to determine the effective production thickness of the reservoirs. When assessing the injectivity profile when penetrating the injector with the spontaneous hydraulic fracturing, the key role belongs to non-stationary temperature logging. In this case, it is necessary to take into account the specific features of temperature relaxation in the wellbore after the injection cycle, related to hydraulic fracturing, primarily the increase in the relaxation rate with increasing fracture length.

Improvement of acid solutions for stimulation of compacted high-temperature carbonate collectors

The object of research in this work is the intensification of hydrocarbon production. The most problematic task of the study is the efficiency of intensification of compacted high-temperature carbonate reservoirs. Despite the gradual transition to renewable energy sources, natural gas and oil will play a dominant role in the world's energy balance in the next 20–30 years. Carbonate rocks have significant mining potential, but low filtration properties require intensification to improve reservoir permeability. High temperatures and pressures at great depths require the improvement of existing hydrocarbon production technologies. The most popular method for treating reservoirs containing carbonates is acid treatments in different variations, but for effective treatment it is necessary to achieve deep penetration of the solution into the formation. The study solves the problem of selection of effective carrier liquids for the preparation of acid solutions for the treatment of compacted high-temperature reservoirs with high carbonate content. To ensure quality treatment, acid solutions must have low viscosity and surface tension coefficient, low reaction rate, their chemical properties must ensure the absence of insoluble precipitates in the process of reactions with fluids and rocks, as well as be environmentally friendly. To select the most optimal carrier liquid, experiments were conducted to determine which candidate liquids provide the minimum reaction rate of acidic solutions with carbonates. Based on the analysis of industrial application data and literature sources, water, nephras, methanol, ethyl acetate, and methyl acetate were selected for further research. Widely studied acetic acid was chosen as the basic acid. Studies have shown that methyl acetate has a number of advantages, namely low reaction rate, low viscosity and surface tension coefficient. As well as the possibility of hydrolysis in the formation with the release of acetic acid, which significantly prolongs the reaction time of the solution with the rock and the depth of penetration of the active solution into the formation.

Minimizing Carbon Footprint by Smart Sustainable Reservoir Management

Sustainability and reducing carbon footprint has attracted attention in the oil and gas industry to optimize recovery and increase efficiency. The 4th Industrial Revolution has made an enormous impact in the oil and gas industry and on analyzing carbon footprint reduction opportunities. This allows classification of various reservoir operations, installation of permanent sensors and robots on the field, and reduction of overall power consumption. We present an overview of new AI approaches for optimizing reservoir performance while reducing their carbon footprint. We will outline the significant carbon emissions contributors for field operations and how their impact will change throughout the production's lifecycle from a reservoir. Based on this analysis, we will outline via an AI-driven optimization framework areas of improvement to reduce the carbon footprint considering the uncertainty. We analyzed the framework's performance on a synthetic reservoir model with several producing wells, water, and CO2 injecting wells. Beneficial in reducing carbon emissions from the field is the reuse and injection of CO2 for enhancing hydrocarbon production from the reservoir. One hundred different scenarios were then investigated utilizing an innovative autoregressive network model to determine the impact of these components on the overall carbon emission of the field and determine its uncertainty. The conclusions from the analysis were then incorporated into a data-driven optimization routine to minimize carbon footprint while maximizing reservoir performance. The final optimization results of the showcase outlined the ability to reduce the carbon footprint significantly.

Leveraging Acoustic Logging for Identification & Quantification of Induced Fractures

The main objective of the acoustic logging in 15K openhole multistage fracturing completions (OH MSFs) is to identify the fracture initiation points behind pipe and contributing fractures to gas production. The technique will also help to understand the integrity of the OH packers. A well was identified to be a candidate for assessment through such technique. The selected well was one of the early 15K OH MSF completions in the region that was successfully implemented with the goal of hydrocarbon production at sustained commercial rates from a gas formation. The candidate well was drilled horizontally to achieve maximum contact in a tight gas sandstone formation. Similar wells in the region have seen many challenges of formation breakdown due to high formation stresses. The objective of this work is to use the acoustic data to better characterize fracture properties. The deployment of acoustic log technology can provide information of fractures initiation, contribution for the production and the reliability of the isolation packers between the stages. The candidate well was completed with five stages open-hole fracturing completion. As the well is in an open hole environment, a typical PLT survey provides the contribution of individual port in the cumulative production but provides limited or no information of contributing fractures behind the pipe. The technique of acoustic logging helped to determine the fracture initiation points in different stages. If fractures can be characterized more accurately, then flow paths and flow behaviors in the reservoir can be better delineated. The use of acoustic logging has helped to better understand the factors influencing fracture initiation in tight gas sandstone reservoirs; resulting in a better understanding of fractures density and decisions on future openhole length, number of fracturing stages, packers and frac ports placement.

Media corrosiveness and materials resistance at presence of aggressive carbon dioxide

At the present stage of gas field development, the products of many mining facilities have increased content of corrosive CO2 . The corrosive effect of CO2 on steel equipment and pipelines is determined by the conditions of its use. CO2 has a potentially wide range of usage at oil and gas facilities for solving technological problems (during production, transportation, storage, etc.). Simulation tests and analysis were carried out to assess the corrosion effect of CO2 on typical steels (carbon, low-alloy and alloyed) used at field facilities. Gas production facilities demonstrate several corrosion formation zones: lower part of the pipe (when moisture accumulates) and top of the pipe (in case of moisture condensation). The authors have analyzed the main factors influencing the intensity of carbon dioxide corrosion processes at hydrocarbon production with CO2 , its storage and use for various technological purposes. The main mechanism for development of carbon dioxide corrosion is presence/condensation of moisture, which triggers the corrosion process, including the formation of local defects (pits, etc.). X-ray diffraction was used for the analysis of corrosion products formed on the steel surface, which can have different protective characteristics depending on the phase state (amorphous or crystalline).

Recovery Factor Improvement; A Success Story of Improving 10% of RF in Greater Natih Reservoirs, North of Oman

Recovery Factor Improvement (RFI) is a process to check the hydrocarbon production efficiency by incorporating the actual static and dynamic field data, as well as the way how the field being operated. This has been a common process within Shell's portfolio since 2018 (Ref; Muggeridge et al., 2013 & Smalley et al., 2009). The approach has been developed to stimulate the identification of new opportunities to increase the recovery from the existing fields and to aid the maturation of these opportunities into the Opportunity Realization Process. There are four (4) factors that affected overall reservoir recovery factor, they are: Pressure efficiency; related to which pressure can be reduced in the reservoir as dictated by the relevant facilities and wells.Drainage Efficiency; the proportion of the in-place hydrocarbon that is pressure-connected directly to at least one producing well on a production timescale.The "secondary pay" efficiency; takes into account the volumes of poorer quality rock in which the gas remains at pressure above the lowest pressure just outside the wellbore (Pf) when the reservoir is abandoned.Cut-off Efficiency; the proportion of hydrocarbon that is lost due to non-production of the tail.This approach was applied in the dry gas Natih Reservoir fields in the PDO concession area. Before the implementation of RFI, the average recovery factor for Natih was around 70%. This was considered low for a homogenous-dry gas reservoir. The targeted Natih fields were benchmarked against each other with a total of 11 fields with similar reservoir properties. Post the benchmarking exercise, the expected field recovery factor is approximately ~90-93%. The team managed to map out the opportunities to achieve the targeted RF and identified the road map activities. The activities are mainly related to: production optimization: retubing, re-stimulation reduce drainage: infill drilling, horizontal well reduce the field intake through compression The outcome of the mapping was then further analyzed through integrated framework to be matured as a firm-project. The new proposed activities are expected to add around 9% additional recovery to the existing fields. There will be a remaining activities which will be studied in the future, example infill wells and intelligent completions. These will close the gap to TQ and add other addition RF of 11-13%. As conclusion, the RFI was seen as a structured approach to better understanding the field recovery factor based on the integrated surface and subsurface data with a robust analysis to trigger opportunity identification linked to RFI elements. It is similar concept as sweating the asset by generating limit diagram for each recovery mechanism & the road map to achieve the maximum limit. This paper will highlight the Natih Fields RFI analysis, highlighting the key learning and challenges.

Energy Resources Exploitation in the Russian Arctic: Challenges and Prospects for the Sustainable Development of the Ecosystem

According to the forecasts made by IEA, BP, and Total in early 2021, the demand for hydrocarbons will continue for decades, and their share in the global energy balance will remain significant. Russia, as a key player in the energy market, is interested in maintaining and increasing hydrocarbon production, so further exploitation of the Arctic energy resources is an urgent issue. A large number of onshore oil and gas projects have been successfully implemented in the Arctic since the 1930s, while recently, special attention has been paid to the offshore energy resources and implementation of natural gas liquefaction projects. However, the implementation of oil and gas projects in the Arctic is characterized by a negative impact on the environment, which leads to a violation of the ecological balance in the Arctic, and affects the stability of its ecosystem, which is one of the most vulnerable ecosystems on the planet. The main goal of the present study is to understand how the implementation of oil and gas projects in the Arctic affects the ecosystem, to assess the significance of this process, and to find out what the state and business could do to minimize it. In the article, the authors analyze energy trends, provide brief information about important oil and gas projects being implemented in the Arctic region of Russia, and investigate the challenges of the oil and gas projects’ development and its negative impacts on the Arctic environment. The main contributions of this paper are the identification of all possible environmental risks and processes accompanying oil and gas production, and its qualitative analysis and recommendations for the state and business to reduce the negative impact of oil and gas projects on the Arctic ecosystem. The research methodology includes desk studies, risk management tools (such as risk analysis, registers, and maps), brainstorming, the expert method, systematization, comparative analysis, generalization, and grouping.