Academic literature on the topic 'Asset-based capacities'

Abstract Modern energy asset planning requires the synthesis of many multi-disciplinary inputs to translate reservoir data into coherent simulations and their associated economic forecasts for effective decision making. Utilizing a nodal network model to integrate well forecasts with the asset's operational considerations allows for improved accuracy of the simulations, better guidance and generation of insights that allow for subsequent optimization of plans and more effective capital allocation. A novel asset development planning workflow is presented which combines type curves with pad scheduling logic, surface flow constraints, costs, ownership, and price forecasts to model the cash flow of the asset through its full life. Flow capacities, costs, shrinkages, liquid yields, and carbon emissions are input at their representative nodes, enabling dynamic and accurate incremental evaluation. Existing base production and corporate type curve databases are leveraged to streamline the workflow, and several scenarios and sensitivities are examined. The novel workflow is compared against a more traditional method using average infrastructure costs and high level capacity assumptions. As a result of enabling more nuanced operational inputs, the nodal network was able to predictively simulate an asset's value within the given constraints and dynamically re-evaluate the full model after inputs were adjusted. For example, the model could automatically reroute production when a constraint was hit, then evaluate the liquid extraction and fee structure based on the new routing. Each iteration's production forecast included the latest base production, well forecasts, drilling schedule shifts, facility throughput constraints, shut-ins expected due to nearby scheduled fracs, third party offtake and fee structures, carbon emission costs, liquid extractions, and "take or pay" penalties. The outcome was a more accurate representation of incremental economics associated with development options, insight into potential optimizations, and improved quality of capital allocation decisions. In addition, the novel workflow was less cumbersome to manage than the traditional workflow. In the conventional process, obtaining accurate network inputs first requires assumption of the flow path. Any subsequent adjustment to the drilling schedule or type curve can change the production timing and routing, requiring the analysis to be manually redone. The traditional method of planning from the type well database alone does not allow a practical means of incorporating schedule and flow details, especially when the plan changes frequently or when considering multiple scenarios. The resulting forecast relies upon broad assumptions that may be materially incorrect in some cases, preventing optimization of planning decisions. Recent systems integrations allow sharing of data between tools which enables more powerful computational methods for improved forecasting and decision making.

Abstract Ship evacuations in Arctic waters expose crew and passengers to the potential for severe life-safety consequences. Effective planning and allocation of Arctic SAR services should be supported by evidence-based assessments of the consequence severity of ship evacuations. This paper provides an evaluation of life-safety consequence severity for ship evacuation scenarios in the Canadian Arctic. Exposure time is a predominant factor influencing consequence severity of Arctic ship evacuations. The study integrates existing models for exposure time estimation [1,2] and life-safety consequence [3]. Exposure time is estimated for air- and marine-based SAR assets, considering associated capacities, speeds, and operating ranges. Evacuation scenario factors include ship type, number of POB, and geographic location. The methodology provides Arctic SAR service providers with a tool for planning effective resource allocation and response efforts. As a base case, exposure times and consequence severities are estimated for SAR response with a single asset. The effect of deploying multiple SAR assets is demonstrated. Results indicate that the deployment of air-based SAR assets contributes to reduced exposure times and mitigation of life-safety consequence severity. Evacuation of a passenger vessel is a worst-case scenario. Evacuations of high POB vessels require the deployment of multiple SAR assets to prevent potential disastrous life-safety consequences.

Abstract This article presents a case study in which subsurface evaluations regarding projects maturity and its associated risks combined with technological and schedule planning integration between three O&G greenfield Capital Projects have enabled a significant reduction in their stage-gate activity duration, enhanced procurement strategies and mitigation of execution phase risks, thus maximizing asset value. The adopted approach considered time spacing the three projects and an integrated governance to track projects and expedite decision-making process from concept and technology selection to authorization and execution phases, still allowing for individual project maturity and singularity to be considered. Risk mapping, evaluation and management were also structured from a unified perspective, including those related to the lifecycle of innovative technologies applied. Throughout the whole process, the standardization of documents and project management routines was also carried out. One of the first observed results was increased agility in the stages of technical specification elaboration, revision, and independent technical assurance, leading to a 5-month reduction in Phase 3, before final investment decision gate coupled with high maturity scores. The resulting integrated procurement strategy was also successfully executed, maximizing bid attractiveness and critical suppliers’ capacity allocation, thus allowing projects to award long lead items contracts just after final investment decision gate. Synergies between projects such as similarities and time spacing have also enabled contracts to incorporate the possibility of adopting new technologies, e.g., wells completion. A secondary, but no less important, advantage of this integrated strategy was the reduction in the internal resources required to conduct the time-consuming process of identifying, evaluating and defining mitigation plans for the threats and opportunities of the three capital projects. One example refers to Buzios field gas management which was improved based on the synergies between projects when selecting FPSOs capacities and technologies. Finally, an innovative approach to decision-making workflow, procurement strategies, and management practices, were essential to ensure the successful alignment of each capital project with corporate objectives, as well as enabling the use of new technologies based on project needs and suppliers’ capacities.

Abstract Managing a large fleet of offshore structures is a dynamic process that aims at minimising risks to personnel, environment, and businesses, as well as minimising the associated Operations Expenditure. Through the collaborative efforts of ADNOC Offshore and Kent, formerly Atkins Oil & Gas, (Atkins, 2020), revised structural evaluation and integrity approaches have yielded significant cost savings. The considerable savings were associated with the elimination of the requirement for installing many new offshore structures and through reducing the subsea inspection associated efforts. The approach for evaluating the offshore assets’ structural performance was developed based on adopting target probability of failure figures subject to each asset's consequence of failure. Accordingly, structural reliability analyses were conducted specific to each structure, where the analysis considered structure specific environmental hazard curves and failure surfaces. Through mapping the evaluated structural probability of failure and ADNOC's corporate risk matrix's HSE Likelihood, each structure was precisely placed on the risk matrix. Furthermore, the inspection intervals and Topsides, Splash Zone, Subsea Levels I, II and III were mapped to each risk evaluation on the risk matrix. The optimisation approach of adopting a structure specific reliability analysis and mapping with ADNOC's corporate risk matrix yielded considerable cost benefits while providing a more accurate representation of each asset's risk. As a result of the implementation of the developed process, approximately 41% of the assets got lower risk evaluation compared to the legacy approach and presented extra structural capacities that can be utilised for future expansions and eliminating the requirement for installation of new assets. As the process expanded to include asset inspections, the subsea inspection requirements reduced by approximately 43% reflecting a considerable decrease in operating costs. A major contribution of the risk improvement is attributed to the consideration of the storm prevailing approach directions, the joint probability of wave and current magnitudes and directions, as well as the relative alignment of each structure. The developed approaches provide a framework that allows continuous update of the risk assessment and enables executives and management to make risk-based-decision supported by a consistent measure of structural risk. This has been translated into the generation of the Structural Passports (Summary reports) clearly demonstrating the assets current risk and recommendations for mitigation measures, if deemed required.

Abstract With the move to Net Zero there has been increased demand to utilize pipelines to transport carbon dioxide. As part of these efforts, repurposing hydrocarbon pipelines is an attractive option. The advantages of repurposing existing pipelines rather than building new ones include minimum disturbance to people and the environment, and reduced capital expenditure. While existing documents provide guidance of an overall process to convert, they do not delve into granularity surrounding scoping metrics to screen potential opportunities from impractical applications. Interdependencies of key considerations such as capacity, operating pressure, fluid composition and phase composition will be described with a sequential decision-based methodology proposed. The purposed methodology is a front-end project screening tool recommended to be used in collaboration with business development prior to investing in detailed engineering evaluations of selected candidate pipelines. This further evaluation is required after screening to evaluate the current state of the asset, define specific flow capacities under both summer and winter conditions, class location assessment, detailed consequence modelling and project risk registry to capture all risks. Cost considerations applicable to the detailed assessment will be discussed to support high level assessment of project viability. Examples of typical hydrocarbon pipelines in Alberta are provided to demonstrate the application of the methodology in scoping potential conversion projects. From these examples, it is evident that conversion to gas phase service is typically feasible whereas there are fewer pipelines capable of conversion to dense phase service. Even with conversion being technical feasible, the project must be commercially viable. Gas phase conversion candidates may struggle to meet capacity demands. Whereas, dense phase conversion candidates may be hindered by additional costs associated with modifications identified in detailed engineering. The final decision on whether to convert or not to convert depends on accurate detailed assessments of all the details including the cost of the assessment itself. This paper provides an approach to screen projects for viability before undertaking detailed engineering assessments to provide a more tactical approach to building out carbon dioxide pipeline networks.

Abstract Carbon capture and storage is a viable short-to-medium term strategy to reduce emissions and support a low-carbon economy. However, geological storage of CO2 in Giga-tonne scales requires many injection wells, leading to complex integration of multiple CO2 plumes. Based on a decade of CO2 storage operation at the Canadian Aquistore CCS project, this paper explores the potential CO2 plume commingling and subsequent pressure buildup during clustering of large-scale geological CO2 storage operations. To assess the significance of multi-well CO2 injection on storage capacity and injectivity, we constructed a static regional model that characterizes the storage and sealing formations. To understand the potential repositories, traps, and sealing mechanisms, the regional model considered 23 wells in the region to build a robust structural framework, utilizing the geological information, interpreted 3D horizons, well tops, and reservoir properties populated based on 3D seismic porosity volumes. A section of the regional model was selected to match the Aquistore injection history and to evaluate the impact of multiple injection wells and CO2 plumes within the area of interest. The dynamic reservoir model was calibrated to the injection data up to year 2020. The history matched simulation model was then used to predict the injection history for the next three years, until 2023. The simulation forecast was compared against actual field data in the same timeframe to assure the simulation model is capable to predict the CO2 storage operation. Different CO2 injection scenarios were employed for dynamic reservoir simulations for the next 20 years with varying injection rates. The injection pressure was constrained to a value below 95% of fracturing pressure determined from an earlier mini-frac test. We monitored the commingling of the CO2 plumes from different wells under a range of reservoir and operational uncertainties. To address the regulatory concerns, the degree of pressure interference between each adjacent CO2 injectors was used to observe the influence of each CO2 injection well before and after the integration of individual CO2 plumes. Lastly, enhanced operational and adaptive pressure management strategies for the CO2 injection wells were discussed to mitigate the potential subsurface risks, maintaining the injection rates and storage capacities within safe limits. Utilizing eight years of actual field data from the Aquistore CO2 injection site is an asset to better understand the CO2 plume evolution and the associated regional pressure buildup in saline aquifers. The modeling results provide valuable insights into the safe and long-term management of multiple CO2 plumes, and showcase the importance of clustering of large-scale geological CO2 storage projects for operators and regulators.

Abstract The purpose of this paper is to present an overview of the Búzios 7 Capital Project, its features, and main achievements. It combines innovative concepts, schedule optimizations and interface management techniques that have allowed a significant reduction in stage-activity duration, mitigation of execution phase risks and application of some technologies for the first time, thus maximizing asset value. The overall approach considered an integrated governance to track project and expedite decision-making process from concept and technology selection to authorization and execution phases. Project conception and execution was based on field maturity and singularity that enabled the adoption of procurement strategies that take into consideration a high-capacity leased unit, full EPCI SURF and an integrated contracting strategy regarding wells construction to enhance market attractiveness. Also, the inclusion of new technologies under development with field proven ones as contingency in case of delays. During the entire project, lessons learned from previous projects, documents standardization and project interface management routines were also carried out. A 5-month reduction in final investment decision (FID) gate combined with high maturity scores was obtained due to the increased agility in the stages of documentation elaboration, revision and independent technical assurance. An integrated procurement strategy including similar projects allowed Búzios 7 to award long lead items contracts as soon as FID milestone was achieved. The project introduced the first high-capacity FPSO of Petrobras (225.000 bpd of oil and 12.000.000 Sm3/d of gas) and novel technologies through its unit e.g. the first leased unit with closed flare concept. Other initiatives seeking for decarbonization was considered such as CO2 stream reinjection into the reservoir, waste heat recovery units and process streams heat integration. A robust well construction design was implemented enabling the first successful installation of a 7 5/8" production string on Petrobras in the well 7-BUZ-74D-RJS of Búzios 7 module, increasing the potential productivity of the well by 14,4%. On the same well there was another successful first, the Shear Gas Lift Valve, increasing the reliability of the gas lift system. The first full EPCI SURF contract in Buzios field was adopted enhancing design and installation schedule and effectiveness. This approach commingled with contractual flexibilities based on the minimum and maximum lengths of lines allowed the project to deal with reservoir information gathered during project execution minimizing risks and allowing optimizations to be captured. These results have reflected a gain of about 5% on Búzios 7 overall oil production curve and enhanced project economics results. The methodologies and results presented help to enhance future offshore endeavors. It addresses a systematic management approach passing through all project phases allowing the adoption of new technologies based on project needs and suppliers’ capacities and an innovative approach to decision-making workflow, procurement strategies, and management practices. The first oil of the Búzios 7 Project is planned to be on the first trimester of 2025 and the maximum capacity of the FPSO (225,000 bpd) by the end of 2025.

Abstract eCalc is the name of a software tool for high-quality emission forecasting. eCalc allows integration of subsurface and operational knowledge and calculates emission forecasts directly relating drainage strategy to operational strategies and equipment. Emissions directly relating to reservoir drainage (CO2 in particular) vary with the reservoir production rates and pressures, and the process assumptions. Emissions from drilling, flaring and mobile vessels may be included for integrated bookkeeping. eCalc is a holistic asset prognosis tool for calculation of the total emissions allowing break-down into single emission sources. eCalc has integrated energy functions to be used for modeling the energy usage of various process equipment such as pumps, compressors, generators, and turbines. The energy functions are models that relate input variables to energy consumption. The input variables are typically rate and pressures. For the compressor models, it uses compressor curves and thermodynamical models to calculate the shaft work needed for the predicted compression work through a single or a series of compressors. Also, it has built in models for future low-pressure projects, for less mature tie-in projects and new builds where vendor data is not available. In addition, there is also support for energy functions based on tables generated by external software (e.g. Unisim, Hysys). The flexibility of the software allows evaluating varying subsurface drainage strategies combined with process modifications in an integrated calculation. The tabulated energy functions, or likewise thermodynamical calculations, allow for a fast and easy to use calculation tool that can be used in multi-realization systems like the fast model update environment. eCalc is batch callable in Unix and can thus be easily integrated in workflows. eCalc also allows integration with external software, like for example numerical optimizers. eCalc uses process knowledge to mimic anti-surge and minimum flow without needing iterative solvers. Depending on where the operating point is relative to the chart, eCalc implements control strategies to automatically mimic process control. Eg if the operating point is in the surge domain, eCalc adds mass rate to the rate input to move to a point on the control line. A forward model results which is at the core of the calculations. It is not intended to replace the commercial process simulation software but allows subsurface personnel access to simplified process calculations and therefore opens the possibility for a better cross-disciplinary working environment. The integrated tool makes mutual information exchange between operations, subsurface and sustainability disciplines easy. The engineering approach with real physical models, capacities and data provides a high-quality emission forecast suitable for the long term. eCalc has been implemented on nearly all Norwegian installations (Espelid et al, 2022) and three generic examples are included in this paper.

Abstract Southeast offshore India reservoirs have high-temperature deep water wells with significantly high pressures and unconsolidated sandstone formations. Controlling sand production is a major issue from inception to well completion and throughout the life of the well. A high density brine is required due to the high bottom hole pressures, thus executing sand control operations using such a high density brine as the base fluid for the gravel pack carrier fluid combined with the elevated temperatures is a significant challenge. A case is presented where a high-density temperature-resistant gravel packing fluid was optimized for a BHT of 320°F using a high-density brine. Additionally, the pH of the fluid was crucial considering the significant presence of CO2 in the formation, which was anticipated to affect asset integrity due to corrosion at low pH. A biopolymer-based fluid with oxidizing breaker was required in 14.2 ppg potassium-cesium formate brine and 12.5 ppg potassium formate brine. The fluid required evaluation for rheology and stability at 320°F, and at a shear rate of 170 s-1 with two conditions of viscosity to be sustained in the range of 75- 150 cP and 150-250 cP for the initial four-hour duration. The same fluid, after four hours, was also required to be broken within fourteen days. The fluid with the optimized formulation in regard with stability and rheology was further required to pass an acceptable sand suspension of ≤ 5% settling. Finally, the optimized fluid was required to show negligible corrosion effects on the downhole metallurgies. The stability and rheology were studied using a HPHT concentric cylinder viscometer. The sand suspension and corrosion characteristics were studied using an HPHT autoclave. The same fluid was studied with an acid breaker as a contingency for wells without CO2-related issues. After an extensive study, 12.72 gal/Mgal liquid gel concentrate of biopolymer when hydrated in 14.2 ppg and 15.45 gal/Mgal liquid gel concentrate of biopolymer, when hydrated in 12.5 ppg, providing viscosity in the range of 150-250 cP with 3 gal/Mgal and 5 gal/Mgal oxidizing breaker were selected, respectively. The optimized formulations passed sand suspension and had a pH in the range of 8-10, which imparted negligible corrosion loss to chrome- and nickel-based metallurgies. At the same conditions, the fluid showed acceptable results with 20 gal/Mgal organic acid breaker where the pH was ≤ 7. The combination of a commonly used biopolymer and a mixed formate brine produced a thermally stable fluid with unconventional chemistry, applicable for high-temperature, high-density conditions. With further study, it is expected that the temperature limit of this fluid can be extended beyond 320°F. The formulation for potassium formate brine was also tested at using field scale equipment to check for ease of mixing, reproducibility of results and for determining friction values when pumped at a certain rate via shunts. The fluid was mixed with relative ease using standard batch mixers and replicated the properties that were determined on a lab scale. The fluid also depicted superior proppant carrying capacities and lower friction numbers than expected which would enable lowering of overall surface pressures and surface pumping requirements.

The prospects offered by hydrogen as part of the energy transition and the decarbonization of the energy system are major topical issues. Although sources of natural hydrogen have been identified in various parts of the world, it is not possible to estimate at this time the potential of these sources, nor to assess their exploitation capacities without further exploration. Thus, hydrogen is not a primary energy source but should only be considered as an energy carrier. Most of this hydrogen, produced today from fossil resources mainly for industrial usage (including oil refining and ammonia synthesis), will have to be obtained tomorrow from decarbonized processes and used more widely for other industrial applications (notably to reduce the carbon footprint of steel and cement production) and for heavy mobility. Given that hydrogen production must be guided primarily by the need to reduce greenhouse gas emissions, this report aims to define what is meant by "decarbonized" hydrogen, which must take precedence over all carbon-based hydrogen. The aim of this report is to clarify how hydrogen can be produced with minimal emissions of greenhouse gases, consider the significant needs it will generate in terms of electrical energy production1, on this basis identify the most appropriate uses for it in the future and derive estimates of a reasonable level of hydrogen production and consumption. The production of hydrogen by water electrolysis, which appears to be a key element in terms of carbon dioxide emissions (CO2), is really decarbonized if the electricity employed for its production is low carbon (nuclear or renewable), which is far from being the case in Europe or at a worldwide level. For the time being, the European electricity mix is largely carbon-based, and its use to power electrolyzers would lead to CO2 emissions twice as high as those of the conventional methane synthesis process. With its remarkably low carbon electricity mix, France has a major asset in playing a pioneering role in the deployment of low carbon hydrogen, provided that the new electricity production capacities required are rapidly available and themselves low carbon. The present analysis underlines the importance of the industrial competitiveness challenge of developing electrolyzers with the highest possible performance, in the service of national energy sovereignty. Efforts in this field deserve to be supported by scientific and technological research into the energy efficiency of electrolyzers and fuel cells, issues relating to reducing the environmental footprint of these components, improving their stability and lifespan, and, more generally, all the elements in the value chain (tanks, new materials, materials and molecules for storing and transporting hydrogen, etc.). The report also highlights the need to guide choices and developments through life-cycle analyses carried out across the entire value chain. The safety issues in using hydrogen are of major importance. New scientific and technological knowledge is essential if one wishes to define safe hydrogen applications. For applications envisaged outside industrial areas, one has to ensure that protocols and regulations remain compatible with their dissemination. Analysis of the future uses of carbon-free hydrogen indicates that, applications should initially be mainly in: (i) the industrial field, essentially to defossilize the industrial processes that emit the largest amounts of greenhouse gases (notably steel and cement production) and to replace grey hydrogen in current industrial uses (synthesis of ammonia and methanol); (ii) the field of heavy transport (sea or air), notably by enabling the synthesis of alternative fuels to replace current fossil fuels.