The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Hosseinzadehsadati, Seyedbehzad (Technical University of Denmark) | Amour, Frédéric (Technical University of Denmark) | Hajiabadi, Mohammad Reza (Technical University of Denmark) | M. Nick, Hamidreza (Technical University of Denmark)
Abstract CO2 injection in depleted oil and gas reservoirs has become increasingly important as a means of mitigating greenhouse gas emissions. This study investigates coupled multiphysics simulations of CO2 injection in chalk reservoirs to better understand the complex thermo-hydro-mechanical-chemical (THMC) processes involved. Two compositional models are created: an isothermal model and a non-isothermal model. Since temperature impacts on fluid compositions have introduced errors in estimating the reservoir's compositions, we made certain simplifications on fluid compositions for the thermal model to address this issue. By using the simplified model, we simulate the temperature propagation of cold fluid into a hot reservoir to observe induced thermal stress due to temperature changes. Despite these simplifications for geomechanical modeling, the propagation of CO2 in the depleted gas reservoir was calculated without considering thermal effects, assuming that the density and viscosity of CO2 remained constant with temperature change in the coupled simulation. Our findings provide valuable insights into the THMC processes involved in CO2 injection in the depleted gas reservoir and highlight the importance of accurately modeling thermal effects to improve simulation accuracy.
Abstract Pressure data can be used to identify possible leaks in a CO2 storage site. However, conventional diagnostic plots used during gas production cannot directly be used to interpret the data, because CO2 properties have a different pressure dependency compared to the hydrocarbon gas initially in place. This paper investigates the possibility of adjusting p/Z plots for CO2 storage into depleted gas reservoirs to make them suitable for monitoring during injection. The p/Z method is explained analytically for both gas production and CO2 injection. A method is proposed to graphically ensure that the p/Z plot during injection overlies the p/Z plot during depletion – the injection line follows the p/Z plot backwards. The method proposes to use a volume-weighted Z-factor to scale both p/Z and injected volume. This method is verified with compositional thermal simulations in a homogeneous model. The uncertainty of both pressure and Z-factor is investigated and the implications of these uncertainties are discussed. Additionally, the proposed method is tested for reservoirs that do not show volumetric depletion behavior. For a volumetric gas reservoir (straight-line p/Z) without near-wellbore cooling it is possible to follow the original p/Z plot backwards with the proposed method. Cooling of the near-wellbore area causes a temperature induced increase of density. The impact of this phenomenon is less than 4% on the p/Z estimate in the described case. With an analytical estimate of the extent of the cooling area, the p/Z value can be corrected to an error of less than 1.5%. Uncertainty in Z for natural gas and CO2 at reservoir conditions can be significant, but generally result in a low impact on the accuracy of the method. The uncertainty in static pressure is larger with CO2 injection due to the higher fluid viscosity and more uncertain downhole density. For reservoirs with ‘slow gas’ behavior, the proposed method does not result in an overlap with the depletion p/Z plot. However, the method does reproduce the path that methane injection follows. The proposed methodology indicates to what extent the storage is filled and has the potential to identify large leakage of CO2 (>1% of GIIP) for volumetric gas reservoirs. To verify the observed potential leak, it is recommended to perform full field simulation.
The renewable energy sector, particularly the solar PV generation, is to play a key role in the energy transition and decarbonization process and the green hydrogen production is a subsequent element of this decarbonization process as a clean energy carrier. When power output from these renewable installations exceeds the grid requirements, instead of stopping the energy generation, that power surplus can be used to produce hydrogen by electrolysis process. Despite being a technically simple process to produce via electrolysis, fuel cost and equipment are the two most significant economical elements to consider as part of the LCOH equation and act as economical boundary conditions. Combining an in-depth analysis while applying the financial modeling toolbox, this project has evaluated specific conditions for solar PV installations in Morocco and Saudi Arabia markets in terms of a techno-economic analysis for a potential investment for green hydrogen production in 2021 as well as near future projections in 2023 and 2025. The most potential application of green hydrogen production and usage is to decarbonize heavy industries (e.g., cement and steel) that cannot be electrified but this will require an extensive transport infrastructure with low-cost incidence for the green hydrogen to be an economically viable solution. Near future projects will require public funding in the form of grants or tax redemption to scale up to economical maturity. After carrying out a detailed financial modeling and a discounted cash flow valuation model, the resulting LCOH for Morocco is $3,2695/kg while Saudi is $1,5757/kg as of the end of 2021 with a projected reduction to reach $2,3678/kg and $1,4417/kg respectively in 2025, which means that by 2025 both countries will be below the $1,5-2,5/kg green hydrogen threshold, on a competitive level with fossil fuels, enabling both countries to grasp unique commercial opportunities to lead the implementation of a green business models towards a hydrogen economy, and eventually a net zero world. The paper will elaborate on the rational driving the need for green hydrogen, will elaborate on the geopolitical framework supporting this emerging business and dives in with the techno-economic analysis while creating a 2023-2025 look-ahead. 2 SPE-214375-MS
Abstract High-CO2 gas fields present a dilemma to Host Government wanting to both ensure security of supply and achieve net zero aspiration. While carbon capture and storage (CCS) technology holds promise of technical feasibility to unlock these fields, its commercial success ultimately hinges on the choice of an appropriate business model. This study compares the economics of the traditional business model i.e., CCS as part of the upstream petroleum operation dedicated to a Production Sharing Contract (PSC) vs. the alternative business model i.e., a regional CCS hub separately managed by a Special-Purpose Vehicle (SPV). To maximize the return on its investment in a gas value chain, Host Government aims to minimize the upstream cost of gas (COG), which in turn comprises the technical cost, fiscal/tax charge, and cost of capital components. Thus, in this paper, the business models are compared in terms of their COG, and the reasons for the differences are further analyzed by looking at the drivers affecting the components. To illustrate the comparison numerically, synthetic technical data based on several recent CCS projects are evaluated under Malaysian petroleum fiscal arrangement and tax regime. The scope of the CCS projects contemplated in this study is restricted to managing the CO2 inherent in upstream high-CO2 gas fields. The paper finds that the alternative business model outdoes the traditional in several ways. The economies of scale of a hub design optimize capital expenditure, while utilization by multiple users reduces hub operator’s risk, potentially lowering tariff. The SPV can better realize tax incentives and also benefit from a lower tax rate. In PSCs where cost recovery provisions prioritize operating expenditure over capital expenditure, upstream Contractors may prefer paying tariff per usage rather than building their own CCS facility up front. Access to cheaper financing from environmental, social, and governance (ESG) investors and government agencies, coupled with the perception of lower business risks, should also translate into a lower cost of capital. There are various spin-offs and qualitative benefits too. While the paper affirms the intuitive expectation that the alternative business model generally surpasses the traditional, it also cautions that the optimal choice may switch beyond certain thresholds (number of fields, distance between PSCs, volume of CO2, etc.). In addition to the between-model selection problem, the paper also discusses within-model fine tunings and optimization. This paper lays out important caveats and considerations that might be of interest to petroleum authority and government policymakers tasked with the development of business model for upstream CCS projects.
Abstract The staggering vulnerability of most conventional energy sources has caused the need to diversify the energy mix for most countries, if not all with most recent issues. Subsequently, numerous countries are experiencing a surge in energy demand and are confronted with the need to meet this increase in energy demand with a response to be ‘clean energy’ at an affordable price. The scope of this paper focuses on defining the different drivers and strategies that developing countries are utilizing to transform their local and interconnected energy sector. For ‘developing’ countries, the primary (current-) focus is on the fundamental commitment for energy diversification (e.g., energy security) in order to achieve sustainable self-sufficient energy source/s that are less impacted by socio-economical or geo-political factors. Furthermore, in this paper, specifically, the case study of Albania will be explained and how its strategy aligns with the global energy transition pathway. Additionally, the paper explores new alternative energy sources; technologies that before were barely considered, and how/why they are being deployed for adoption.
Abdelkareem, Sherif Shaban (TU Clausthal / Equinor) | Grimstad, Alv-Arne (SINTEF) | Bergmo, Per Eirik (SINTEF) | Gaol, Calvin Lumban (TU Clausthal) | Jahanbani Ghahfarokhi, Ashkan (NTNU) | Lothe, Ane Elisabet (SINTEF) | Ringstad, Cathrine (SINTEF) | Ganzer, Leonhard (TU Clausthal)
Abstract The latest report of the UN International Panel on Climate Change (IPCC) has affirmed once again the urgent need for carbon capture and storage (CCS) to realize the international climate ambitions. Deployment of CCS technologies is a fundamental key to reach the 1.5°C climate target since the estimated global technical geological CO2 storage capacity is 1000 gigatons, which is higher than the CO2 storage needs through 2100. In this study, the dynamic carbon dioxide storage capacity for a potential CO2 storage site in the Trøndelag platform is investigated. The Garn formation of the selected site in the Norwegian Sea has promising geological characteristics and is here considered to be the main storage formation. A conceptual geological model has been built based on the available geological data which have been mainly extracted from the literature. Three main realization models representing different porosity and permeability ranges are constructed. Dynamic reservoir simulation studies for each realization are run with an injection rate of 2 million tonnes per year for 50 years and continued for 70 years of post-injection. Sensitivity analyses investigate different parameters’ effect on the CO2 plume, pressure development, and CO2 storage capacity. The sensitivity parameters include relative permeability, injection rate, number of injection wells, perforation length, boundary conditions, fault transmissibility and capillary pressure effects. The results after 120 and 240 years of total simulation time, show the clear effect of saturation functions on plume migration and CO2 dissolution into the water phase. The porosity and permeability variations within a specific range have a minor effect on the pressure development and dissolved/trapped CO2 amounts but mostly affects the CO2 plume shape, extent, and migration speed. Doubling the injection rate using one well will increase the dissolved and trapped CO2 amounts by more than 70% and 90% by the end of simulation, respectively. While injecting the doubled CO2 amount using two wells will lead, up to 130 % and 115 % rise in the dissolved and trapped CO2 amounts, respectively. For both cases with the double injected amount, the increase in the average field pressure during injection is about twice the increase in the base case. A sharp rise in the average field and near-wellbore pressures has been noticed when the boundary conditions are closed demonstrating the importance of hydraulic communication with the wider connected pore volume, represented through analytical Carter-Tracy aquifers in the base case scenarios to represent the semi-open full volume of the Garn Formation. Without the external pore volume, a sharp increase in formation pressure led to an automatic shutdown of the injection well which caused a reduction in the injected CO2 amount. Increasing the perforation length of the injection well, eliminating fault transmissibility as well as including a non-zero capillary pressure showed no significant effect on CO2 plume, and pressure development after 120 years of simulation, while a slight change in the dissolved and trapped CO2 amounts is observed. The effect of these sensitivity parameters may be obvious if the simulation time is increased. This study mainly confirms that this structure in the Trøndelag Platform can store up to 200 Mt of CO2 as predicted in previous work. This makes the selected structure a potential CO2 storage site in the Norwegian Sea for future CCS projects.
Al-Hajri, Hamood S. (Petroleum Development Oman) | Al-Sawafi, Marwan (Petroleum Development Oman) | Al-Hashimi, Abdulaziz R. (Petroleum Development Oman) | Al-Hadidi, Khalsa (Petroleum Development Oman) | Al-Kindi, Osama M. (Petroleum Development Oman) | Al-Amri, Mohammed (Petroleum Development Oman) | Al-Abri, Mohammed (Petroleum Development Oman) | Al-Hinai, Suleiman (Petroleum Development Oman)
Abstract Water and chemical EOR are the main secondary recovery mechanisms in many heavy oil fields in Oman. The development concept during EOR phase is through intense infill drilling with narrow well spacing. Field-M is currently under secondary recovery phase with both water and chemical EOR (Polymer) development. During this phase, water production increases significantly and all undesired water is being disposed through disposal wells. This increases carbon intensity as disposal process generates CO2 emissions with no additional benefit, which considered as uneconomical emissions. Due to increased amount of produced water during this phase, water handling capacity (including water disposal) was fully utilized to maximize oil production from this field. Creative solutions were certainly needed reduce uneconomical water disposal and increase oil gain. As per the field development, certain pre-defined polymer dosage need to be mixed with treated produced water to achieve a viscosity of around 15 cp to ensure effectiveness of chemical EOR. Field-M injection strategy was suggested to be under controlled fracture condition to maximize throughput. In controlled fracture injection environment, monitoring fracture propagation is very important as it can cause direct interference with producers leading to injection fluid short circuiting. Fracture propagation can be determined using pressure fall off test. In addition, water quality must be monitored regularly as it plays a major role in fracture propagation. Effective surveillance and sampling plan was generated and implemented to ensure to ensure effectiveness of the polymer injection and to capture any opportunities related to increasing injection within the field. The analytical work showed that fracture propagation is a function of injection pressure, injection rate, fluid properties (in this case produced water quality and polymer quality) and in-situ stresses. Most of this parameters are controls though effective surveillance, metering & sampling. However in-situ stress condition is dynamic as the reservoir pressure keeps changing based on dynamic changes in injection and offtake. Thus, fracture propagation was monitored carefully through periodic temperature surveys and pressure fall off test to identify opportunities to optimize injection in some of the injectors. The findings from these activities enabled increasing injection rate up to 30% in some of the injection patterns. This optimization provided additional sink for the produced water reducing water disposal and uneconomical CO2 emissions by at least 5%. This is considered this as the first step toward zero water disposal goal. In addition increasing injection in these patterns resulted in significant increase in oil gain associated with polymer injection peaking to maximum of 42% in some of the injector/producers patterns. The effective use of surveillance data was key enabler to achieve ultimate goal of increasing polymer injection and reduce carbon intensity within the field. This goal was achieved with significant gain of oil.
Abstract Denmark aims at a 70% reduction in greenhouse gas emissions by 2030 compared to levels measured in 1990, with a long-term target of becoming carbon-neutral by 2050. As part of this national effort, the Bifrost project, aims at repurposing two depleted gas fields in the Danish North Sea for CO2 storage, namely the Harald West sandstone field as the primary target and the neighboring Harald East chalk field as a potential upside. The Harald East chalk is the focus of this study. The storage potential and infrastructures available within the multiple chalk fields located in the Danish North Sea represent valuable assets to fulfill the national objectives enabling a time- and cost-efficient implementation of carbon storage activities. One of the main challenges for carbon storage in chalk is the contradictory experimental results reported in literature that indicate both a strengthening and a softening effect of supercritical CO2 on the plastic and elastic properties of chalk. Such uncertainty hampers accurate prediction of the deformation response of storage sites. In this context, the study aims at assessing the impacts of two levels of uncertainty; the type of mechanical alteration induced by supercritical CO2 and the petrophysical heterogeneity on the long-term deformation behaviour of chalk reservoirs. An in-house hydro-mechanical-chemical model calibrated against experimental data on chalk is applied in a reservoir model of the Harald East field. A 16 year-long injection period is simulated assuming two scenarios. In scenario 1, supercritical CO2 has no impact on the mechanical properties of the rock, whereas in scenario 2, a 30% and 25% lowering of the pore collapse stress and elastic modulus of chalk is assumed. A systematic comparison of the flow and mechanical behaviour of low and high porosity cells located in the vicinity of an injection well indicates that the impact of CO2 on the mechanical properties of chalk, the distance of the cells from the injector, the local stress redistribution taking place in the reservoir between mechanically soft and strong cells, and the presence of natural gas in pore space before CO2 injection are key factors controlling the amount and distribution of plastic deformation occurring in the storage site. The outcome of this work enables quantifying the main risks associated with rock compaction close to and further away from injectors during and after carbon storage in chalk fields.
Nguyen, Quang Minh (The University of Tulsa) | Onur, Mustafa (The University of Tulsa) | Alpak, Faruk Omer (Shell International Exploration & Production Inc.)
Abstract Summary This study focuses on carbon capture, utilization, and sequestration (CCUS) via the means of nonlinearly constrained production optimization workflow for a CO2-EOR process, in which both the net present value (NPV) and the net present carbon tax credits (NPCTC) are bi-objectively maximized, with the emphasis on the consideration of injection bottomhole pressure (IBHP) constraints on the injectors, in addition to field liquid production rate (FLPR) and field water production rate (FLWR), to ensure the integrity of the formation and to prevent any potential damage during life-cycle injection/production process. The main optimization framework used in this work is a lexicographic method based on line-search sequential quadratic programming (LS-SQP) coupled with stochastic simplex approximate gradients (StoSAG). We demonstrate the performance of the optimization algorithm and results in a field-scale realistic problem, simulated using a commercial compositional reservoir simulator. Results show that the workflow is capable of solving the single-objective and bi-objective optimization problems computationally efficiently and effectively, especially in handling and honoring nonlinear state constraints imposed onto the problem. Various numerical settings have been experimented with to estimate the Pareto front for the bi-objective optimization problem, showing the trade-off between the two objectives NPV and NPCTC. We also perform a single-objective optimization on the total life-cycle cash flow, which is the aggregated quantity of NPV and NPCTC, and quantify the results to further emphasize the necessity of performing bi-objective production optimization, especially when utilized in conjunction with commercial flow simulators that lack the capability of computing adjoint-based gradients.
Abstract A new approach to acidizing is presented where an inert dry chemical is hermetically sealed inside a metal carrier and deployed downhole via E-line or slickline. The tool is spotted in front of the zone of interest and an exothermic reaction is initiated generating hot acid vapour. A depleted Eocene sandstone reservoir with a 2 7/8″ tubing inside 6 5/8″ casing was successfully treated leading to sustained production enhancement in addition to significant carbon footprint reduction when compared to a conventional treatment. The treatment approach, production results and description of the CO2 reduction is presented. A rigorous well candidate selection process was done as part of the treatment design which analyzed information including damage mechanism, well completion architecture, mineralogy, well deviation, formation type and compatibility. Based on this analysis, the tool type and tool placement sequence were determined to optimize the stimulation. For this well, two 2″ HCl and two 2″ 12:3 HCl/HF tools were used to treat a 5.5 m perforated interval. The HCl tools served as pre-flush treatment and removed any scale. This was followed by 12:3 HCl/HF tools which stimulated the near wellbore matrix and ultimately improved the reservoir fluid influx. After each tool was ignited, a drop in the fluid level was observed. This was positive indication that the acid vapour was enhancing connectivity to the reservoir. When pulled to surface, it was observed that all four tools had ignited and had undergone a complete chemical burn. The well had several tubing and pump changes throughout its long production history. More recently, the well was treated by bullheading EDTA and solvent to re-establish the oil production rate with unsatisfactory long-term production results. Prior to the novel treatment, the well had been producing at 9 – 11 m/d (gross rate) and 1.8 m/d of oil. After the application of the novel technique, the production results showed a return to the historical rate of 1.8 m/d of oil (100% increase). Eighteen months post-treatment, the oil production is sustained and producing between 1.5 - 1.6 m/d. Flow-back equipment was eliminated from the operation since the highly reactive hot acid is fully spent and dissipated. The operation was rigless and the only equipment required was a wireline unit, a crane, and a small fluid truck. The entire stimulation was completed in less than one day and the well could be put immediately back on production. A secondary benefit was a notable reduction in CO2 associated with this treatment method versus a conventional acid treatment. This was achieved by reducing the heavy equipment requirements and the associated diesel consumption.