Abstract The cost of carbon capture is the major impediment in its mainstream acceptance, but its ability to abate the carbon emissions at a considerable scale, makes it a technology with promising potential. The paper presents detailed account of the energy optimization meticulous review carried out for a brownfield project to capture carbon from the Sulphur Recovery Unit (SRU) Tail Gas. The paper demonstrates the vital role of energy optimization in restraining the carbon capture cost. The methodology comprised development of an overall integrated heat & power model of the process encompassing energy supply sources, including power generation and import, and major energy consumers like CO 2 absorption solvent regenerator, CO 2 compressor and dense phase CO 2 pump etc. The optimization was achieved by setting the objective function to minimize energy cost in terms of steam & power demand, by relating the selection of major drivers i.e. electric motor or steam turbine, as well as solvent, with the total energy cost in conjunction with the associated CAPEX. It followed with a meticulous review of individual systems and components. Comprehensive energy optimization exercise, equating energy supply, major drivers’ selection and process decisions with the total energy cost and the associated CAPEX minimization, facilitated in carbon capture cost reduction by more than 10%. The optimized scheme helped in maximizing the utilization of available waste heat as well as in minimizing the spare steam dumping in condensers. The exercise confirmed the absolute significance of the energy optimization measures in reducing the cost of carbon capture.

Abstract CO 2 foam as a fracturing fluid for unconventional reservoir has been of huge interest due to its potential in solving various challenges related to conventional water-based fracturing. The rheological property of CO 2 foam is a key factor controlling the efficiency of fracturing process and it is strongly influenced by different parameters such as foam quality, temperature, pressure and shear rate. The quantification of these parameters under reservoir conditions leads to the design of optimum injection strategy. However, the traditional modeling approaches are unable to provide fast and accurate prediction while considering combined effect of all these parameters. Here, we proposed a data driven approach based on supervised deep learning to estimate rheological property of CO 2 foam as a function of foam quality, temperature, pressure, and shear rate. We exploit deep neural networks (DNNs) that are trained to learn the complex nonlinear aspects of the data. For the data generation, we performed a series of experiments for CO 2 foams by varying different process variables. CO 2 foams at different qualities were generated using conventional surfactant in a flow loop system and foam viscosity measurements were performed at HPHT under wide range of shear rate. The architecture of DNN was optimized to accurately estimate the foam apparent viscosity for given foam quality, temperature, pressure, and shear rate. The predictive capability of designed network is found to be significantly high, analyzed by regression coefficient approaching unity, low mean squared error, and low average absolute relative deviation (≪ 2.5%). The designed neural network allows robust and accurate prediction of foam apparent viscosity at different foam qualities under various reservoir condition, which demonstrates its practicality for CO 2 foam projects for fracturing unconventional reservoirs.

Abstract Fusion bonded epoxy coatings (FBEs), due to their zero volatile organic compound (VOC) and less production lines wastes, have increased the customers’ interest in this technology for pipes corrosion protection. However, the high-energy consumption used, to keep the oven at 438°F - 482 °F (225 °C - 250 °C), makes them not very competitive with liquid epoxy coatings (LECs). LECs, cheaper to be applied, using low curing temperatures ranging between 100°F to 212°F (38 °C - 100 °C), faster return-to-service, can perform like FBEs using lower thickness. Here a new LEC able to resist in petroleum, 50 bars CO 2 at 392°F, is reported. The protective behavior of the coating reported, has been investigated using electrochemical techniques too.

Abstract The production of hazardous gases such as CO 2 and H 2 S impose high risks to offshore operations, with lethal impacts on personnel, along with special equipment required and environmental challenges. Hydrocarbon productions require that part of this gas could disperse on the atmosphere, so a comprehensive risk analysis is necessary to evaluate the gas disposal event. Computational Fluid Dynamic (CFD) can be used to effective study how the wind and environment can interfere with the gas dissipation in the air. In this work, a specific analysis was necessary to produce a gas well with up to 80% CO 2 fluid composition. A CFD Gas Dispersion Analysis evaluated the turbulent airflow over and offshore drilling vessel perimeter to map the flammability levels and hazardous gases concentration zones, depending on winds speeds, wind directions, and well gas flowrates. Parallel processing was applied in order to reduce the computing time for simulation of 52 cases on gas release on burner booms and relief lines, and 56 cases for leak analysis on the process plant. The results permitted defining using 3D maps the concentration levels of hazardous gases on the rig expected on each scenario condition, as well as the coverage area outside the vessel affected by the gas release.

Abstract The use of carbon dioxide (CO 2 ) for simultaneous methane recovery and CO 2 storage is gaining recognition globally within the oil and gas industries. On the other hand, most of the residual natural gas recovered during the EGR process is highly contaminated with the injected CO 2 due to their nascent miscibility nature, resulting in premature breakthrough. In this study, N 2 gas was used as a buster to mitigate such early mixing between the CH 4 and CO 2 . The experiment was administered at reservoir conditions of 40oC temperature, 1500 psig of pressure, the optimum injection rate of 0.4ml/min, and at varying N 2 cushion volumes (8-36 cm 3 ) using Bandera gray as the porous medium. Further experimental tests were administered to study the effect of this technique on connate water salinity with 5-20% water salinity been considered. The increase in buster gas volume was in direct proportion to delayed CO 2 breakthrough, with the maximum at 36cm 3 buster volume. This breakthrough occurred at 177 minutes which is 110min additional delayed than the conventional CO 2 flooding with a breakthrough time of 67 minutes. This was due to the high shielding barrier inhibited by nitrogen, making it difficult for the CO 2 to dispersed itself and mixed with the nascent natural gas resulting in delayed breakthrough as it plumes transverses into the CH 4 during the displacement process. Furthermore, a poor performance was observed with the inclusion of the connate water salinity, especially at 20% wt. This was because the free pore spaces were already occupied by connate water molecules prior to the cushion gas injection which hinders its economic potential application.

Abstract Despite the several kinds of literature on the dispersion behaviour of supercritical CO 2 in CH 4 at conditions relevant to enhanced gas recovery (EGR), studies have so far limited in keeping this parameter as low as possible. This study aims to highlight, experimentally, to determine the effect of N2 as cushion gas on the dispersion coefficient in consolidated sandstones core plug under reservoir conditions applicable to EGR. A laboratory core flooding experiment was carried out to simulate a detailed process of an unsteady state methane displacement in Bandera gray and Bentheimer core plugs at reservoir conditions of 40oC temperature, 1500 psig of pressure, the optimum injection rate of 0.4ml/min, and at varying N 2 cushion volumes (8-36 cm3). Further experimental runs were carried out to investigate the effect of high CO 2 injection rates (0.6-1.2 ml/min) on the longitudinal coefficient of dispersion as it plumes transverses into the core plugs during the EGR process. The coefficient of longitudinal dispersion declines with raises in cushion gas volume, hence the higher the amount of N2 cushion volume the less the dispersion of CO 2 into CH 4 . This is due to the high shielding barrier inhibited by nitrogen, making it difficult for the CO 2 to dispersed itself and mixed with the nascent natural gas resulting in delayed breakthrough as it plumes transverses into the CH 4 during the displacement process. The inclusion of N 2 as cushion gas prior to CO 2 injection recorded the highest decline at 36cm 3 cushion volume, presenting a 48 and 28% reduction in longitudinal dispersion coefficient for Bandera and Bentheimer core samples respectively, compared to that of conventional/traditional CO 2 injection (with zero cushion volume). Recording lower nascent CO 2 -CH 4 mixing resulting in less natural gas contamination and more storage volumes. Also, a reverse phenomenon was observed when the CO 2 injection rate was increased from 0.6-1.2 ml/min due to the high diffusion rate of CO 2 at higher interstitial velocities, resulting in a rapid increase in dispersion coeffient and indirectly high widespread contamination of the remaining natural gas.

The soft-SAFT equation of state is employed for the screening of deep eutectic solvents (DES) for CO 2 capture based on key performance indicators, namely, CO 2 absorption capacity, and enthalpy of absorption. This work belongs to a long-term project on assessing the adequacy of advanced EoSs (soft-SAFT) as a tool for the evaluation and design of alternative solvents for CO 2 capture. The models for the pure DESs and their mixtures with CO 2 are validated with experimental data, and subsequently used in a fully predictive manner to calculate the thermophysical properties needed for evaluating solvent performance. Results demonstrate that under the same operating conditions, [TBA][Cl]:LA (1:2) is the most promising DES in terms of amount of CO 2 absorbed and enthalpy of absorption. However, the comparison of these solvents to 30 wt.% aqueous MDEA solution shows that the promise of DESs is far from adequate in terms of CO 2 solubility, being 13 times lower than that obtained with aqueous MDEA. Nevertheless, DESs show a clear advantage in terms of lower enthalpy of absorption, being 3 times less than aqueous MDEA, along with the absence of water as a co-solvent. The collection of the acquired results confirms the reliability of the soft-SAFT EoS as an attractive and valuable screening tool for CO 2 capture and process modelling.

Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing. Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant. The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO 2 , energized, and foamed fluids (CO 2 and N 2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable. This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.

Approximately 40% of current global natural gas resources have high H 2 S and CO 2 concentrations. The H 2 S concentration in Middle East gas reservoirs can potentially reach up to 30 mol%. H 2 S is toxic; therefore, the produced natural gas must be treated and sweetened. In this high H 2 S environment, a membrane technology that can remove the bulk of H 2 S from produced natural gas will reduce the load on the amine treatment and sulfur recovery unit operations downstream in gas processing facilities. Bulk removal of acid gases with membrane technology will lower SO 2 emissions through a reduction in flaring, elemental sulfur production from sulfur recovery units, and reduce unit delivery costs for the life of the field. Since 1984, Schlumberger has deployed cellulose triacetate polymeric membranes for CO 2 removal in gas processing and EOR applications. In collaboration with a major oil and gas exploration and production company, our membrane science research team is testing cellulose tri-acetate acid gas removal membranes to characterize separation performance under a variety of process conditions. The team deployed a pilot system capable of testing gas with 25% H 2 S in the USA. These membranes will separate both acid gas components, CO 2, and H 2 S from the feed gas and retain hydrocarbons in the residue gas sent to the amine system for further processing. Low-pressure acid gas permeate can be reinjected into the reservoir for enhanced oil recovery or sequestration. Initial laboratory testing and predictive modeling of the membranes, completed with an American academic research institution, have shown promising results for bulk H 2 S removal. Pilot system testing data will further de-risk and validate the feasibility of technology deployment and facilitate economic modeling of this technology's business impact. We will present the results of the testing to date which will form the basis of the observations and conclusions of the paper. This paper will also present a case study to show the business impact of deploying a hybrid system (membranes + amine) in comparison to a conventional amine system. After testing, operators will have satisfactory information available to review alternative processing facility concepts and re-evaluate the economics of ultra-sour gas field development projects.

Hydrogen is an essential feedstock for a variety of chemical and industrial processes. Refineries with a global share of over 30% are amongst the largest consumers. Traditional methods of generating hydrogen involve the reformation of fossil-fuel sources with the help of steam. These methods release CO 2 as a side product and are thus carbon-intensive. A zero-carbon approach of producing hydrogen can be achieved via electrolysis of water powered by surplus renewable energy sources, which in return helps to balance the intermittency of solar photovoltaic (PV) or wind. Hydrogen is also often a by-product of industrial processes. These synthetic waste gases have typically been flared in the past. Burning these gases in gas turbines instead can significantly boost the economic case and reduce carbon emissions compared to flaringbecause of the utilization of the waste energy. Gas turbines are typically designed for natural gas operation, and accommodating high levels of hydrogen poses significant challenges due to its different physical properties. First, hydrogen is the lightest molecule with a lower volumetric energy content and higher diffusivity. This has an impact on the fuel delivery system, as sealings and piping materials need to be upgraded. Second, local mixing between fuel and air may not be perfect as hydrogen flames tend to stabilize further upstream, where mixing quality is lower and are more compact. As hydrogen has a higher flame temperature, local hotspots can lead to higher NOx emissions. This, in return, may require performance adaptations to meet the local emissions standards. Perhaps the most challenging aspect of hydrogen use in turbines is its significantly higher reactivity. Hydrogen has a substantially higher flame speed (up to 10 times) and lower ignition delay time than natural gas, which increases the risk of flashback and explosions. To overcome all these challenges and guarantee safe operation with high hydrogen fuels, focused development is required, particularly with regards to the combustor. Following an iterative rapid prototyping approach, the design optimization is typically achieved via high-fidelity ComputerAided Engineering(CAE) simulations coupled with validation through high-pressure testing at engine conditions. Here, the use of Additive Manufacturing (AM) for generating prototypes has been a critical success factor in recent years. In addition to reducing the overall lead time by up to 70%, AM offers the opportunity to generate and manufacture more efficient aero designs for e.g., cooling and fuel routing schemes. This paper focuses on the use of hydrogen in gas turbines and discusses the required development steps. General challenges of accommodating hydrogen in gas turbines and the implications on design modification and operation will be examined in detail. Examples of achieving up to 100% hydrogen operation on a 25MW scale gas turbine from recent testing programs will be subsequently presented. Use cases of gas turbines operating with high hydrogen fuels in industrial processes will alsobe discussed.

Fossil fuels currently supply more than 85% of world's energy, and global energy demand and consumption is forecasted to go up rapidly over the next 20 years [ Jamaloei et al., 2011 ]. Such demand can only be satisfied by sustaining the production of energy in existing fields. Therefore, Enhanced Oil Recovery from existing fields has become increasingly important. Polymer flooding is one of the most efficient EOR technologies that started as early as the late 1950s [ Standnes et al., 2014 ]. Adding polymers increases the viscosity of the injected fluid downhole, which helps to push out viscous crude oil for better oil recovery (up to 10-15% over water flooding) [ Standnes et al., 2014 ] [ Taylor et al., 1998 ]. Among them, Hydrolyzed polyacrylamide (HPAM) is gaining popularity in EOR: inexpensive, it can also withstand high mechanical forces during water flooding [ Li et al., 2016 ] [ Wever et al. 2011 ]. Depending on salinity and temperature, co and ter-polymers of PAM with ATBS may be more relevant to be efficient in highly stressed conditions. Depending on process conditions, industrial equipments such as water pipelines and flowlines are built in seamless carbon steel (CS), stainless steel (SS) and especially duplex (DSS) or superduplex stainless steel (SDSS), capables of transporting fluids at high temperatures and pressures. Since produced water or seawater used in EOR processes bring species prone to induce corrosion (most notably carbon dioxide, hydrogen sulfide and sulfate, dissolved oxygen), several corrosion modes are possible : uniform corrosion of CS, pitting and crevice corrosion of SS, Microbiologically Influenced Corrosion (MIC). Technologies such as upstream deoxygenation of the fluids, addition of oxygen scavengers and corrosion inhibitors and/or addition of biocide are used [ Voordouw, 2011 ]. The corrosion mechanisms of CS in synthetic and industrial brines in presence of CO 2 and H 2 S are often studied, but the effect of viscosifying polymers on corrosion is not well documented. This study aimed to improve the knowledge on the effect of PAM based viscosifying polymers on corrosion of CS and SDSS.

The poor volumetric sweep efficiency for secondary and tertiary oil recovery processes is mainly caused by reservoir heterogeneity, whether sandstone or carbonate reservoirs. Reservoir heterogeneity is usually characterized by permeability anisotropy and permeability contrast of the formation. Because of the problems of permeability anisotropy and permeability contrast of low and high permeable zones, most of displacing agents are injected into the high permeable zone. When the displacing agent is produced from production well, the displacing efficiency is extremely ineffective. In other words, large quantities of oil remain in the low permeable zone, which is un-swept by displacing agent. In this study, we used In-Situ sc-CO 2− Emulsion as a conformance control agent to plug the high permeable zone, and then improve the volumetric sweep efficiency of the low permeable zone in a carbonate formation. To achieve this goal, we studied the effect of two types of conformance control patterns on tertiary oil recovery performance by sc-CO 2 miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are classified as follows: (1) isolated the low permeable zone and opened the high permeable zone, and (2) opened both the low and high permeable zones when a base-gel system was injected into the core plugs after initial sc-CO 2 flooded. Two physical models consisted of carbonate core plugs set up initially to carry out the core flooding experiments of displacing oil and obtained the remaining oil saturation by water flooding as a secondary oil recovery process. The preliminary sc-CO 2 injection was conducted following water flooding to recover the remaining oil after water flooding as a tertiary oil recovery mode. The practice of the conformance control patterns using In-Situ sc-CO 2− Emulsion generated by injecting base-gel system into the core in which had the presence of sc-CO 2 was performed after the preliminary sc-CO 2 injection. The second sc-CO 2 injection was conducted following base-gel system injection. All experiments were under reservoir conditions. The base-gel system used in this study consisted of polymer and surfactant. The experiments of stabilization and apparent viscosity measurement of the base-gel system and CO 2 emulsion were conducted at varying experimental conditions. Based on the results and observations of the characteristics of study on the base-gel system and CO 2 emulsion, core flooding experiments, the practice of the conformance control patterns with in-situ sc-CO 2− Emulsion, and second sc-CO 2 miscible injection, the in-situ sc-CO 2 emulsion was generated successfully in the formation in which was the presence of sc-CO 2 . The volumetric sweep efficiency and oil recovery under the conformance control patterns using in-situ sc-CO 2 emulsion was improved for both physical models. Also, the production performances were compared for both physical models before and after base-gel system injection in this paper.

Miscible gas injection is a proven enhanced oil recovery method for medium-light oils. Miscibility is typically assessed with the slimtube experiment, which aims at identifying the minimum pressure (MMP) above which the displacement process is multi-contact miscible and leads to low microscopic residual oil saturation. During implementation of a miscible gas injection scheme, there will often be areas close to producing wells where the reservoir pressure is below the MMP and the question then arises whether the process can still be considered miscible. Another complicating factor occurs in reservoirs with significant lateral fluid property variation, where it is not intuitively clear how the MMP varies aerially. We employ compositional reservoir simulation to investigate the impact of flowing bottom-hole pressures below MMP on the development and propagation of a miscible front. Starting with 1D simulations, we track a number of important properties such as the effluent gas composition over time, the component K-values at distinct positions along the displacement front, as well as the pressure at the front over time. Due to the high gas mobility, the pressure drop per unit distance is greatly reduced in the areas flooded by gas. This means that the reservoir pressure at the gas-oil front is higher than the pressure at the same position before arrival of the front. Therefore, a miscible displacement can be maintained even when not only the flowing bottom-hole pressure but also the average reservoir pressure is below MMP. A key requirement is, of course, that the gas is injected at a pressure above MMP. We evaluate various parameters in terms of their ability to distinguish between miscible and immiscible displacement and find that the phase density difference versus pressure provides a unique advantage for estimating the MMP and we believe it can be used not only in 1D slimtube simulations but also in other thermodynamics-based algorithms. We also find that the vapor mole fraction, inferred from GOR measurements, is a better metric than GOR itself and that molar ratios applied to the effluent gas are very useful for tracking miscibility.

The molecular-based soft-SAFT equation of state has been applied to describe the chemisorption of CO 2 in non-aqueous hybrid solvents of mixtures of AMP and glycols. The reactive nature of the CO 2 absorption process in non-aqueous amines was implicitly modelled by the formation of CO 2 -amine physical aggregates bounded by strong and localised intermolecular interactions. This modelling framework only required VLE data on the absorption of CO 2 in amine solvents, without the need for additional information such as speciation reactions or equilibrium constants. Subsequently, the developed models were used to examine the CO 2 capture performance of these hybrid solvents in terms of absorption cyclic capacity and heat of regeneration as key performance indicators using a simple and short-cut estimation method. Results show that for the same total amine mass concentration, non-aqueous AMP solvents possess a 30-40% decrease in total heat of regeneration compared to their aqueous counterparts at the expense of a 20-50% reduction in cyclic capacity. These results validate the reliability of the molecular modelling approach as an attractive and valuable tool for the screening of chemical solvents and process modelling.

The cost of carbon capture is the major impediment in its mainstream acceptance, but its ability to abate the carbon emissions at a considerable scale, makes it a technology with promising potential. The paper presents detailed account of the energy optimization meticulous review carried out for a brownfield project to capture carbon from the Sulphur Recovery Unit (SRU) Tail Gas. The paper demonstrates the vital role of energy optimization in restraining the carbon capture cost. The methodology comprised development of an overall integrated heat & power model of the process encompassing energy supply sources, including power generation and import, and major energy consumers like CO 2 absorption solvent regenerator, CO 2 compressor and dense phase CO 2 pump etc. The optimization was achieved by setting the objective function to minimize energy cost in terms of steam & power demand, by relating the selection of major drivers i.e. electric motor or steam turbine, as well as solvent, with the total energy cost in conjunction with the associated CAPEX. It followed with a meticulous review of individual systems and components. Comprehensive energy optimization exercise, equating energy supply, major drivers’ selection and process decisions with the total energy cost and the associated CAPEX minimization, facilitated in carbon capture cost reduction by more than 10%. The optimized scheme helped in maximizing the utilization of available waste heat as well as in minimizing the spare steam dumping in condensers. The exercise confirmed the absolute significance of the energy optimization measures in reducing the cost of carbon capture.

Increase in the requirement of reduction of CO 2 emission / carbon footprint demands the need for CO 2 capturing units in existing gas treatment facilities. The location of the CO 2 capturing unit in the sour gas treating plant have economic impact with respect to CO 2 recovery and unit technical cost (UTC). A case study is presented to demonstrate the optimum location of the CO 2 recovery unit with available licensed technology. Based on production profile and composition for Asab 1 & 2, the potential acid gas removed from acid gas removal unit (AGRU) is quantified. The amount of CO 2 in acid gas to be recovered in view to having a SRU unit, had the choice of CO 2 recovery from: (1) low pressure amine based CO 2 capturing units, (2) high pressure CO 2 capturing units based on amine / physical solvents, or (3) CO 2 recovery from tail gas of sulphur recovery unit (SRU). A technology selection study was carried out to select appropriate technology for CO 2 capture with optimum unit technical cost (UTC). The study findings are summarized as below: Low pressure amine based CO 2 recovery unit, along with the tri-ethylene glycol (TEG) based CO 2 dehydration and conditioning and CO 2 pumping / compression units configuration, is considered to have optimum unit technical cost (UTC). The low pressure amine based CO 2 recovery unit acts as an acid gas enrichment (AGE) unit upstream of the sulphur recovery unit (SRU). As the CO 2 is recovered, the total enriched acid gas feed (with higher H 2 S concentration) to sulphur recovery unit will reduce, hence the size of the sulphur recovery unit (SRU) will come down. Tri-ethylene glycol (TEG) based CO 2 drying technology is considered with advantage over other available technologies like mole sieves, membrane based process etc. The CO 2 capturing unit scheme selected during the conceptual design stage will be further developed in detail during the FEED stage. The CO 2 recovered will be utilized for enhanced oil recovery, which will aid increased oil production and value to the company. As the CO 2 recovery unit is planned along with SRU, the CO 2 emission from the SRU unit will also be reduced.

Global carbon emission reduction targets and how to meet them are high on operators’ agendas. Quantifying greenhouse gas (GHG) emissions created across every segment of the hydrocarbon extraction and production value chain is an essential step in this process. It's already widely acknowledged by operators on the UK Continental Shelf that drill cuttings treatment at the well site can materially reduce costs and improve safety by avoiding the need to collect, contain and transfer cuttings by sea and road freight to a specialist processing facility onshore, as required using the traditional "skip and ship" method. It's also widely accepted that by reducing the transport and logistics involved in skip and ship processing, carbon emissions are also greatly reduced, but by exactly how much had not been precisely quantified. In order to support operators’ understanding of their carbon footprints towards drilling waste management specifically, TWMA performed a study to establish the comparative carbon footprint for a portable thermal processing drill cuttings processing unit, treating drill cuttings on a standard offshore platform, versus that of a typical skip and ship to shore operation. The study investigated the carbon footprinting process, interpreted recognised guidance and set system boundaries and emission scopes. The carbon footprint associated with each method of treatment was then calculated, based on carbon dioxide equivalent (CO 2 e) per tonne of drill cuttings functional unit. Furthermore, a carbon calculator was created to establish a carbon footprint comparison capability for any well within the North Sea. The results revealed that the carbon footprint of the current skip and ship operation is 53% higher than that of a portable unit treating drill cuttings at typical North Sea well site. Furthermore, and based on the lower estimate of drill cuttings produced on the UK Continental Shelf, additional benefits will include: the diversion of 28,000 tonnes of waste powder from landfill; the recovery of 6000 m 3 of produced oil for re-use in the offshore drilling system; and 6000 m 3 of water that requires no further wastewater treatment. This study is the first of its kind to show a direct CO 2 comparison between offshore processing and the skip and ship cuttings disposal method. It has increased the awareness of the CO 2 e emissions associated with each process. As the industry moves towards a lower carbon future, it provides a solution to significantly reduce the carbon emissions of drilling operations whilst also improving safety and reducing well cost.

Several challenges are associated with the characterization of low permeability reservoirs, most significantly for the enhance oil recovery operations. The scope of this work presents the integration of petrophysics data and its application in selection of the Microfrac intervals to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO 2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. The case study concentrates on the multiple carbonate reservoirs that consists of a succession of clean limestone and intermittent dolomitic limestone. The complex carbonate lithology and fabric combined with low permeability presents a challenge to conventional logs and evaluation. Detailed integration of advanced and conventional logs (resistivity, neutron/density, advanced acoustic logs, Dielectric, NMR, Borehole image), Pressure testing & Sampling, Microfrac in-situ stress measurements and analysis plays a critical role in characterizing the reservoir properties and enhance oil recovery operations. Extensive data gathering is conducted with wireline suite, which covered Advanced Straddle Packer/Pressure Test & Sampling - Resistivity/Density/Neutron/Spectral GR – Acoustic logs – Resistivity Image – NMR – Dielectric technologies for reservoir properties of multiple carbonate reservoirs. The advanced acoustic analysis is performed in order to study elastic properties of the formation along with identifying transverse and azimuthal anisotropic intervals. The Geomechanical modeling is performed and stress profile is calculated to identify intervals with a stress contrast, which is important for the following stress measurement interval selection. The Microfrac in-situ stress measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO 2 injection capacity for effective enhance oil recovery within these reservoirs. The conventional logs, advanced logs, and Microfrac in-situ measurements and analysis enabled reservoir characterization and development plans for enhance oil recovery operations. The NMR technology provided lithology independent total porosity, permeability estimations and reservoir rock quality. Advanced multifrequency Dielectric measurement provided the fluid saturation in the invaded zone and textural parameters. Advanced Acoustic and image logs provided the geomechanical properties that enable to choose the best intervals for the following Microfrac stress measurement. Geomechanical workflow allowed identifying stress measurement intervals with a good stress contrast in multiple carbonate reservoir intervals. The data integration work illustrated in the paper is a key for any reservoir characterization that enabled property evaluation and successful Microfrac stress measurement. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO 2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.

The production of fuel and chemicals in many countries is based on fossil sources but concerns about reservoir limitations and greenhouse gas emissions are shifting the focus towards solutions to increase the efficiency of processes and decarbonise these markets: the objective of this paper is to provide an overview on low-carbon intensity technologies that are instrumental to the decarbonisation of the energy industry. Hydrogen is the most promising low-carbon intensity energy vector. However, it is mainly produced through hydrocarbon steam reforming which generates 9 to 12 metric tons of CO 2 per ton of produced hydrogen. A key factor in driving the energy transition and achieving a low-carbon future is therefore the potential to obtain low carbon intensity hydrogen – through carbon capture solutions producing blue hydrogen, using biofeedstocks within adapted steam reforming applications to produce biohydrogen, or via water electrolysis utilizing renewable power. The blue hydrogen technology described in this paper results in more than 90% CO 2 emissions reduction due to the integration of an advanced steam reforming solution with pre-combustion carbon capture. While blue hydrogen, which is produced from hydrocarbons, is able to significantly reduce the emissions to the atmosphere, but still produces some CO 2 , biohydrogen is instead a carbon neutral solution achived via modified steam reforming of liquid biofeedstock. This technology has the potential to be carbon negative when enhanced with a carbon capture system. Another aspect of the decarbonisation process, Substitute (or Synthetic) Natural Gas (SNG) from biomass gasification, biogas upgrading and power-to-gas systems is the most promising and immediate solution among the hydrocarbon-based fuels. SNG product has great market possibilities in refining, and automotive sectors or for injecting into pipelines for the upgrading and re-purposing of distribution networks. The product is a clean carbon alternative to conventional natural gas that can be distributed using the existing grid infrastructure. Wood is pleased to present this paper to introduce the above-mentioned technologies for hydrogen and SNG, with the aim to provide viable and alternative solutions to industrial operators who are looking to support the economy decarbonisation securely and create a more sustainable future.

Fusion bonded epoxy coatings (FBEs), due to their zero volatile organic compound (VOC) and less production lines wastes, have increased the customers’ interest in this technology for pipes corrosion protection. However, the high-energy consumption used, to keep the oven at 438°F - 482 °F (225 °C - 250 °C), makes them not very competitive with liquid epoxy coatings (LECs). LECs, cheaper to be applied, using low curing temperatures ranging between 100°F to 212°F (38 °C - 100 °C), faster return-to-service, can perform like FBEs using lower thickness. Here a new LEC able to resist in petroleum, 50 bars CO 2 at 392°F, is reported. The protective behavior of the coating reported, has been investigated using electrochemical techniques too.