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Session 1 – Experimental
G. Ualiyeva, E. A. Dilsiz, E. Pereyra, C. Sarica; The University of Tulsa, USA; R. Coutinho, ExxonMobil Upstream Integrated Solutions Company; J. Cai, ExxonMobil Upstream Integrated Solutions Company
ABSTRACT
Investigation of downward flow is relevant due to the downward inclination of transport lines, injection of chemicals and CO2 as part of Enhanced Oil Recovery (EOR) operations, and possible operation in a two-phase flow region while transporting and injecting a mixture of CO2 and contaminants during CO2 capture and underground storage. However, downward two-phase flow is one of the areas least studied in multiphase flow, with limited experimental data and modeling studies. Moreover, previously acquired experimental data shows that existing models fail to accurately predict flow parameters for downward flow.
This paper presents an experimental study of low-viscosity oil and air flow in a 2-in downward inclined pipe (-45°, -60°, and -70°). Experimental data includes flow patterns from video observations, average liquid holdup from quick closing valves (QCV), pressure gradient from differential pressure transducers, and wall-liquid shear stress from constant temperature anemometer (CTA). Liquid and gas superficial velocities vary from 0.1 to 1.6 m/s and 1 to 7 m/s, respectively. Stratified Wavy (SW), Stratified Wavy with Thin Film (SW-TF), Slug (SL), and Pseudo-Slug (PS) flows are observed for given experimental conditions. Experimental results are compared with the most commonly used software, based on mechanistic models for predicting flow patterns, liquid holdup, pressure gradient, and wall-liquid shear stress. A parametric study using the Taitel & Dukler (1) model is performed for stratified flow conditions to evaluate the contribution of each variable in the model. Results show that the experimental wetted perimeter is higher than the calculated one due to the aeration of the bottom film, resulting in lower wall-liquid shear stress.
A. Arabi, R. L. Höhn, Y. Stiriba, J. Pallares; Departament d’Enginyeria Mecànica, Universitat Rovira i Virgili, Tarragona, Spain
ABSTRACT
The injection of steam and enriched hydrocarbon gas into subsurface formations, as well as carbon capture, utilization, and storage (CCUS), involve gas-liquid vertical downward flow. This paper aims to advance the understanding of the three flow regimes associated with intermittent vertical downward flow which are cap bubble, slug and churn flows. First, a series of visualizations were conducted using a high-speed camera on an air-water mixture flowing in a 30 mm ID pipe. The observations notably revealed the complex nature of the slug-to-churn flow transition, marked by the apparition of droplets and disturbance waves, as well as the disappearance of Taylor bubbles in favor of wisps. Then, new cap bubble-to-slug and slug-to-churn flow transition models are proposed. The developed models were evaluated using both the reported flow observations and a database collected from the literature. A good prediction level was achieved.
N.R. Kesana , H. Andersen, E. Grammeltvedt, P.S. Johansson, Equinor, Norway, A.Vestvik, O.Rinde, Gassco, Norway
ABSTRACT
A film extractor device has been designed and constructed to measure liquid entrainment in high-pressure gas dominated systems. Despite extensive research on liquid entrainment, many studies lack realistic field conditions. This article presents valuable experimental data with hydrocarbon fluids to validate and improve droplet entrainment models. Two-phase and three-phase flow droplet entrainment experiments have been conducted in Equinor’s three-inch high-pressure multiphase flow loop in a horizontal orientation, using hydrocarbon gas, condensate and aqueous-MEG (77% MEG by wt) as fluid phases. The experiments have been performed for system pressures of 30 bara and 90 bara and the water-cuts 0, 20, 40 and 100%. Several sensitivity studies and operational strategies have been implemented to understand the performance of the film extractor and the experimental results. Liquid entrainment trends for varying gas and liquid flow rates show significant liquid entrainment under high system pressure. The entrained fractions of condensate are significantly higher than for MEG/water. Furthermore, it should be noted that entrainment trends are strongly influenced by the gas density, superficial gas velocity, liquid film flow rate and fluid properties. This new experimental data can be used to validate the entrainment models in commercial multiphase flow simulators. There is less data available for high-pressure systems, and entrainment shall affect liquid accumulation and pressure drop, which is more important to low liquid loading systems. A good estimation of droplet entrainment is needed for these low liquid loading systems.
Session 2 – Slugging Part 1
M. Klinkenberg, S. Orre; Equinor, S. Belfroid; TNO, A. S. Tijsseling; Eindhoven University of Technology
ABSTRACT
In recent years, experimental campaigns and theoretical evaluations have increased the understanding of the forces exerted by multiphase flow on pipe bends, leading to vibrations in the pipes. Most published measurements have been conducted using air and water under atmospheric conditions. Computational Fluid Dynamics (CFD) simulations indicate that the RMS force values decrease at higher pressure. An experimental campaign at Equinor’s flow facility in Porsgrunn, where forces on pipe bends were obtained from acceleration measurements combined with a mechanical response mode, confirms this trend. Water, oil, and gas were used as fluids. This paper utilizes force data collected at 20, 40, 60, and 80 bar to adapt an existing two-phase and low-pressure RMS force correlation for elevated pressures up to 80 bar. A high-pressure correction coefficient, depending on gas density, is introduced into an existing atmospheric RMS force relation. Experimental data not used for tuning confirm an accurate prediction of the RMS force. Furthermore, the results of a stochastic mechanistic model of the slug force acting on a pipe bend are compared with the measurements. The computations result in higher RMS forces than those obtained from the acceleration measurements and the mechanical response model. To ensure a safe usability in fatigue design, the correction coefficient is set covering both the experimental results and the computations.
R.S. Esteves, Petrobras, BR; J.F.C Lorenzeti, Petrobras, BR; T. R. Takahashi, Petrobras, BR; V. A. P. Arraes, Petrobras, BR; G. R. de Azevedo, Petrobras, BR; M. L. de Matos, Petrobras, BR.
ABSTRACT
A Petrobras non-associated gas field platform operates wells with a subsea manifolded system and a processing plant serving as hub for import-export, facing challenges such as high-pressure plant, continuous MEG injection for hydrate prevention and liquid accumulation in long pipelines causing slugs. During a production test campaign, one well liquid loaded mainly due to high backpressure and lack of monitoring alarms. Many alternatives were studied to reverse the situation and some deemed risky for the reservoir or required critical resources planning. This case study highlights the team’s expertise and use of transient simulations to address liquid loading challenges in gas wells.
J-B. Flutte, R. Khiari, C. Candelier, TotalEnergies, France
ABSTRACT
Deep offshore production lines face numerous daily challenges that can compromise sections and sometimes the entire subsea network. Maintaining stable operations and avoiding the occurrence of slugging flow regime can sometimes be challenging. Pressure instabilities can cause operational disruptions, equipment fatigue, and potential risks to the integrity of the production systems. It is essential to understand the mechanisms behind these fluctuations to develop effective mitigation strategies and ensure the smooth functioning of the production lines.
Two operational support studies were carried out to address different types of slugging observed in various assets: well-induced slugging and terrain-induced slugging.
Session 3 – Data analytics, I.M., M.L. and A.I.
E. Karagoz, C. Nogueira Sondermann, E. Pereyra, C. Sarica, The University of Tulsa, USA
ABSTRACT
Slug flow is one of the most common two-phase flow patterns encountered in pipelines and surface facilities, especially in upward and horizontal systems. Its dynamic structure, including slug body and gas pocket, poses a risk of integrity failure by fatigue in pipelines, elbow structures, or separators if not properly designed. Therefore, accurate slug characterization is essential for reliable pressure loss calculations and appropriate sizing of the pipeline and separator, including integrity and safety aspects. This paper presents a detailed computer vision approach to experimentally characterize slug and near-slug conditions, such as transitions to stratified and pseudo-slug flows. The approach is assessed using experimental data from a three (3) in. inner diameter acrylic flow facility at the University of Tulsa. The superficial liquid velocities range between 0.1 to 0.45 m/s, while superficial gas velocity ranges from 0.4 to 8.5 m/s, which covers slug, slug to stratified transition, and pseudo slug to slug transition. The computer vision (CV) system identifies the liquid-gas interface to determine essential flow characteristics, including slug and film lengths, slug frequency, holdup, and translational velocity. The research focuses on transition areas to evaluate the CV algorithm’s performance in detecting flow characteristics through comparisons with experimental data and model predictions, demonstrating reasonable consistency of less than 20%. The findings validate the feasibility of applying computer vision as a non-intrusive technique for estimating flow parameters. The article provides recommendations for enhancing the usability of the algorithm, especially for pseudo-slugs, while presenting useful information on flow conditions associated with slug formation and flow pattern transitions.
D.-Jr Peng, Engineering Advanced Analysis, Offshore, Energy, Worley, NL; D. Ibrahimi, G.E. Varelis, Technology and Innovation, Offshore Energy, Worley, UK
ABSTRACT
The separation of oil and water is essential for oil production, as excessive amounts of water must be disposed of in rivers or oceans. Therefore, establishing restricting water specifications that minimise environmental harm is necessary. Gravity separation tanks play a crucial role in achieving the required water specifications before disposal. The water specification is typically assessed based on two key parameters: SIC (Salt-in-Crude) and OIW (Oil-in-Water), which serve as practical measures. Since SIC and OIW are related to the oil particle size distributions within the separation tank, Computational Fluid Dynamics (CFD) techniques are employed to determine SIC and OIW across various separation tank configurations, aiming to optimise separation performance efficiency. This approach leverages computational power to reduce costly separation trials in practice, thereby saving capital expenditures (CAPEX) and minimising waiting times.
Advanced CFD models are generated to simulate the separation process in a single tank, utilising the Eulerian-Eulerian simulations coupled with Population Balance Model (PBM) and accounting for particle coalescence and breakup mechanisms. The CFD predictions are initially benchmarked against historical field measurements and are found to be in close agreement. Such comparisons enhance the confidence in the CFD predictions. Subsequently, further analyses are conducted to evaluate the performance of the separation tank under both parallel and sequential configurations. The results identify the optimal configuration for separation tank performance based on the relationships between SIC/OIW and particle size distributions.
Q. Wang, M. Laghari, R. Vieira, S. A. Shirazi, S. Karimi; The University of Tulsa, USA
ABSTRACT
During oil and gas production and transportation, particles are detached from reservoirs and carried by multiphase flow within wells and pipelines. If the flow velocities in horizontal wells and pipelines are low, these particles may accumulate and lead to blockages, potentially obstructing the flow. To prevent such occurrences, sand transport models are utilized to predict the critical flow velocity required to prevent particle settling. Previous research has developed various models, utilizing both mechanistic approaches and machine learning methods, to address this challenge. Machine learning tools developed previously are based on more than 1,400 experimental cases from variety of sources. These models are highly accurate and are developed for particles moving in gas or a liquid phase. At the same time, mechanistic models have been developed to determine liquid phase velocities in multiphase flows. These models have been used to predict particle transport in multiphase flows, but the accuracy of the models is affected by two factors, first the accuracy of liquid velocity calculations responsible to transport particles and secondly determining liquid velocity in multiphase flows. Thus, to further improve the prediction accuracy and increase computational efficiency, a hybrid machine learning-mechanistic model is proposed in this study. In this model, gas-water two phase flow model is used to calculate key parameter of liquid hold-up and liquid actual velocity. Then, single-phase Machine Learning sand transport model is implemented in the iteration to obtain the critical velocity. This model is then validated by comparison with experimental data for particulate transport in multiphase flow. The performance of the model is also compared to an existing mechanistic model from the literature. The results of the hybrid model show significant improvement over the earlier developed purely mechanistic models and correlations for multiphase flow.
P. T. Bhaskoro; PETRONAS Research, Malaysia, J. Bt. Johar; PETRONAS Carigali, Malaysia, C. F. Torres; PETRONAS Research, Malaysia, L. Wollebaek, H. Lutro, T. Vanvik; Turbulent Flux, Norway , G. B. Falope; PETRONAS Centre of Excellence in Subsurface Engineering & Energy Transition (PACESET), Heriot Watt University, UK, T. Wood, L. Liebana, L. Thomas; Worley UK, Brentford, UK, B. W. E. Norris; Department of Chemical Engineering, The University of Western Australia, Australia
ABSTRACT
Natural gas is an important resource in the current energy transition. It is required to maintain energy security and to support sustainability due its low CO2 emissions. However, the remaining gas fields are mostly marginal and stranded, located offshore at deep water with long tieback (more than 100 km). Current extraction technologies are in many cases not economic, either due to the need for FPSO or offshore platform, high compression energy, high chemical consumption, and large liquid handling facilities requirement.
A novel subsea Pseudo Dry Gas (PDG) technology, including a new in-line separator, has been developed to remove liquids from gas-condensate pipelines, thus significantly lowering pressure drops, allowing higher capacity or lower energy consumption to transport hydrocarbon fluids. The technology has been extensively tested in both low- and high-pressure flow loop systems. This data was also used to develop a real-time transient simulation tool to monitor PDG in-line separator performance and, pipeline hydraulic e.g., slugging and liquid inventory, to enable remote monitoring and control for production enhancement and optimization.
This paper will focus on the interpretation of the measurements and data collected during the flow loop tests and transposing the data for future applications. The output of the work demonstrates PDG can be used for a large range of developments and highlight the performance against the key metrics of superficial gas velocity, superficial liquid velocity, fluid properties, and pressure on the separation efficiency. The paper also presents the process to scaling the PDG unit for real life applications and the outstanding development process for first deployment.
In addition, the paper also presents the simulation of PDG application for a deepwater gas field, at 2,000m water depth, with a 140 km pipeline, with and without PDG system and with actual hydrocarbon fluid composition were used. The optimal line size and the number and location of PDG units were determined based on a flow assurance study.
Comparisons of simulation results with and without PDG shows the benefits of using PDG system, mainly significantly lower pipeline pressure (reduced hydrate risk), smaller liquid inventory in the main gas pipeline and elimination of liquid surges during transient operations (minimize slug handling requirement).
N. Evripidou, Cyprus University of Technology, Cyprus
ABSTRACT
Oil-water dispersed flows are common in the petroleum industry. While gravity-driven separation enables phase segregation, persistent settling layers reduce separation efficiency. This study conducts a parametric investigation using a mechanistic model to identify factors contributing to settling layer persistence. Droplet size, dispersed-phase fraction, and pipe diameter are varied to evaluate their effects. Results, presented as separation regime maps, identify the dominant separation mechanism under different conditions. Smaller droplets, higher dispersed-phase fractions, and larger pipe diameters promote settling layer persistence. A near-linear relationship is also found between droplet size and critical pipe diameter at which a persistent settling layer is observed.
Session 4- Fluids and production chemistry – Part 1
E. Al-Safran, A. Aql; Petroleum Engineering, Kuwait University, M. Ghasemi; Stratum Reservoir, M. Shamsaldeen, and B. Al-Hamad; Kuwait Oil Company
ABSTRACT
Organic deposits in petroleum production systems, such as asphaltene, paraffin, and hydrates, require flow assurance consideration during asset development. As the condition in the reservoir and well changes with time, the stable asphaltene molecules are disturbed, thus precipitating, aggregating, and depositing. Remediation techniques using chemical solvents are not only costly but also have significant health and environmental impacts. Estimating the economic and environmental impact of asphaltene deposition requires an efficient management plan and mitigation strategy. A key item in the success of such a management plan is an accurate estimation of asphaltene deposition rate, characteristics, and location, which requires a simulation tool. In this work, an Asphaltene Integrated Model (AIM) simulation tool is presented, which predicts asphaltene deposition behavior along the production system over time. The AIM simulator is an integrated reservoir/well model that incorporates models of asphaltene precipitation, aggregation, deposition, transport, and thermal-hydrodynamic multiphase flow model, as well as a fluid compositional model. These models are integrated using a PythonTM platform, which numerically links all the models in time and space throughout the production system. A field validation and model tuning study of the AIM model is presented by Al-Safran et al. (2023 and 2024).
In this paper, various simulation case studies investigating the effect of well and reservoir parameters revealed valuable insights into the asphaltene deposition behavior. For example, although asphaltene precipitation increases with water cut, asphaltene deposition decreases due to high shear stresses, which reduces the sticking tendency of asphaltene on the inner pipe wall surface. Furthermore, it has been found that large asphaltene aggregates tend to be transported in the flow stream, reducing the asphaltene deposition rate. In addition, AIM simulator predictions revealed a low asphaltene deposition rate at high production flow rates due to a low asphaltene sticking probability (the ratio of particle wall adhesion force to flow drag force), which re-entrains deposited asphaltene aggregates into the flow stream. In the reservoir, simulation cases revealed that reservoir pressure depletion results in a moderate asphaltene deposition in the near-wellbore region. Moreover, the reservoir rock wettability effect is investigated, which revealed that an oil-wet system results in early asphaltene deposition in the near-wellbore region, making it essential to address these conditions to optimize reservoir performance under asphaltene deposition. Overall, AIM simulation case studies provide insights into asphaltene deposition behavior, enabling field production strategies to prevent, mitigate, and manage asphaltene deposition risk, thereby maximizing economic benefits and ensuring the safety of field personnel.
V. Benito-Iglesias, C. van der Geest, P. Sanz-Sanz, S. Gómez-Álvarez, Repsol Technology Lab, Spain; Á. Vivas, Repsol E&P, Spain
ABSTRACT
The development of offshore projects for heavy crude oil production usually presents significant challenges related to flow assurance, under both steady-state and transient operating conditions. When water starts being produced from the reservoir, the increase in viscosity due to emulsion generation increases the complexity of crude transportation. An accurate emulsion modelling is key to properly estimate the pressure drop along the production system during the design phase. An integrated evaluation workflow was developed in this work to reduce the existing uncertainty on emulsion viscosity and to overcome the limitations derived from experimental data and software modelling functionalities.
Session 5- Hydrate management
T. R. Takahashi, Petrobras, BR; J. F. C. Lorenzeti, Petrobras, BR; R. S. Esteves, Petrobras, BR; V. A. P. Arraes, Petrobras, BR
ABSTRACT
WAG (Water Alternating Gas) injection wells are utilized for secondary recovery in Brazilian pre-salt fields. This method combines the best gas displacement efficiency and the best water sweep. However, there is a risk of hydrate blockage due to gas migration during well closure in the water injection phase. Traditionally, diesel bullheading or continuous MEG injection prevents hydrates in WAG injection wells. In April 2024, the ethanol batch was successfully used as hydrate prevention in a confirmed gas return at the Santos basin. Ethanol offers lower cost but requires careful execution to mitigate blockage risks.
A. Laruelle, A/S Norske Shell, NO; B.-F. Chang, Shell Global Solutions, MY; G. Groote, A/S Norske Shell, NO; S.S. Manley, Shell Global Solutions International, NL, Ø. Koldal, Orlen Upstream Norway, NO
ABSTRACT
Within the operation of Ormen Lange gas field in 2022, multiple infield pipeline blockages were observed. During operation, gas is continuously dosed with Mono Ethylene Glycol (MEG) to prevent hydrate formation. However, if a section of the pipeline is a deadleg (no effective flow in the line), a subsequent risk is hydrate formation. With field experience from these blockages and following dynamic simulations and assessments, recommendations were defined on how to prevent hydrate blockage formation. Blockages can be prevented by restarting flow in the deadleg after a certain period and for a minimum duration.
C. Candelier, N. Lesage, T. Saint Pierre, TotalEnergies, France
ABSTRACT
Hydrates form from water and gas at high pressure and low temperature, common in offshore environments. Plugging by hydrates must be avoided, influencing subsea network design. Traditional deepwater designs avoid hydrate zones, leading to high CAPEX and complex operations. NADAH (New Approach of Design Against Hydrates) offers a new method, leveraging crude oil’s induction properties to delay hydrate formation. This allows safe incursions into hydrate zones, reducing CAPEX, OPEX, and GHG emissions. NADAH has been applied in over five projects, mainly in West Africa, simplifying operations and extending No Touch Time for existing assets, thus saving OPEX and reducing production shortfalls.
J. P. S Oliveira, J.V. Barbosa, J. N. E. Carneiro; ISDB FlowTech, R. L. F. Castello Branco; HAI – Hybrid AI, E. Hayashi, C.V. Barreto; ESSS, R. L. A. Pinto; Petrobras
ABSTRACT
The accurate prediction of hydrate deposition in oil production wells is critical for flow assurance, as hydrate formation can lead to blockages and production losses. In this study, we implemented a hydrate deposition model originally proposed for gas-dominant pipe flow systems into a commercial simulator and extended its application to oil-dominated systems. The model was verified and validated using field cases, assessing its ability to reproduce pressure and temperature trends associated with hydrate accumulation . Our approach involved integrating the deposition model into a transient multiphase flow simulator and testing its performance under conditions typical of oil production wells. The validation process included comparisons between simulated results and field data for steady state operations. The results demonstrate that the model can accurately replicate field-observed pressure and temperature sensor trends indicative of hydrate blockage events. Additionally, the study highlights the sensitivity of the model to operational parameters, underscoring its applicability in real-world production scenarios. The findings support the model’s potential integration into commercial flow assurance workflows, offering a potential tool for predicting and managing hydrate deposition in offshore oil production.
V. O. O. Machado, Federal University of Technology – Parana (UTFPR), Brazil; P. A. D. Maldonado, UTFPR, Brazil; J. P. P. Siqueira, UTFPR, Brazil; M. A. M. Neto, UTFPR, Brazil; G. Lavalle, Mines Saint-Etienne, France; A. K. Sum, Colorado School of Mines, USA; A. Fidel-Dufour, TotalEnergies, France; R. E. M. Morales, UTFPR, Brazil.
ABSTRACT
Gas hydrates are solid compounds that can form and agglomerate in pipelines, posing flow assurance challenges in oil and gas operations. One strategy to mitigate this risk is allowing hydrates to form while using anti-agglomerants to maintain a slurry flow. However, limited research exists on how hydrate-like particles influence multiphase flow behavior. This study investigates the effect of hydrate particles in stratified and slug flow, using air-water and air-oil systems with model particles. Experiments were conducted in a 50-mm inner diameter, 34-m long test section across different particle concentrations. The study provides insights into particle transport and proposes empirical correlations for key flow parameters.
Session 6- Flow assurance
C. Garcia, V. Sinha, S. Wang, and D. Penmetsa, Wood, Production Optimization, USA
ABSTRACT
Oil and gas production operations in deepwater offshore fields pose many flow assurance-related challenges, one of them being the initial field start-up that includes a large number of production and injection wells. The well sequencing order is vital to secure a successful ramp-up of the field with varying reservoir pressures and productivities. The typical flow assurance challenges associated with field start-up operations may include and are not restricted to the initial displacement of the completion fluid from the well tubing, displacement of startup fluid (dead oil) from the flowline/riser, the possibility of hydrate formation, sand production, and flow instabilities that may result in slugging. Therefore, flow assurance and production engineers must have a holistic approach when planning the field start-up operations, with emphasis on both the reservoir/subsea considerations and the topside facility limits.
This paper presents the efforts to investigate feasible field start-up strategies for a major offshore deepwater production system with planned reservoir pressure maintenance through water and gas injection wells. The goal was to achieve a successful field startup while overcoming challenges due to completion drawdown limits, well deliverability, production chemistry, flowline/riser geometry, and the actual topside operational requirements. The analysis included a review of the reservoir production forecast, wells allocation, flow distribution among different flowlines, and the topside operational pressure requirements, which in turn were dictated by field injection needs. Multiple start-up sequencing options were analyzed with variations in well clusters (drill centers) start-ups, alternating characteristics of the first wells being brought online in each loop, usage of test separator versus the main topside’s separators per operational needs, and adjusting the chemical inhibition demands accordingly. Finally, the most optimal start-up sequence was recommended that establishes a stable flow while minimizing the above-described challenges and operating within the system limitations. The entire analysis was conducted using an advanced multiphase flow simulator capable of performing transient flow modeling, essential for capturing the dynamic nature of the physical phenomenon.
C. Candelier, C. Drouilly, V. Richon, A. Fidel Dufour, C. Chalaron, TotalEnergies, France
ABSTRACT
Cold Flow is a novel offshore design approach that allows safe operation within hydrate and wax formation zones. It combines three innovations: paraffin prediction via LedaFlow, hydrate slurry transport using LDHI-AA, and the world’s first Subsea Automated Pig Launcher (SAPL). This strategy reduces CAPEX and simplifies operations by avoiding heavy insulation and complex procedures. Developed internally by capitalizing on progress in R&D and extensive qualification program in specific experimental facilities, it redefines flow assurance by enabling controlled incursions into high-risk zones, offering a cost-effective model for future offshore developments.
Session 7 – Slugging Part 2
- Candelier, J. Sarrasin, A. Cassot, TotalEnergies, France ; B. Eidsvik, G. Ulland, Oceaneering, Norway ; M. Lewis, Xodus Group, United Kingdom
ABSTRACT
Flow-induced vibrations (FIV) can cause fatigue failures in subsea pipelines while being undetected. Screening methods exist but remain conservative for multiphase flows and do not precisely assess fatigue in existing equipment. Reliable simulations have been developed and validated with experimental data, but access to in-situ measurements is still limited. As part of a routine ROV inspection, two spools on an in-service subsea riser tower were observed to be vibrating, and a combined simulation and measurement campaign was engaged upon to quantify the risk of fatigue failure and to optimize mitigation with the installation of mechanical clamp acting as sliding pivot : fewer supports, diverless intervention, and faster installation without shutdown, reducing costs and eliminating human exposure.
E. Elsaadawy, Saudi Aramco, Saudi Arabia
ABSTRACT
A new inlet device was developed to improve the efficiency of Gas Oil Separation Plants (GOSP) by enhancing multiphase gravity separation. The patented device features a twin-cyclonic configuration, designed to handle high-momentum incoming streams and reduce slugging impact. Computational Fluid Dynamics (CFD) validated its geometry, concept, and performance. An experimental program was conducted to test the technology against commercial vane and cyclone inlet devices. This paper presents the experimental setup, procedure, results, and discussions, providing a comprehensive evaluation of the new device’s performance under challenging conditions and its potential to debottleneck GOSP operations.
J. Kjølaas, P. R. Leinan, SINTEF Industry; R. Belt, TotalEnergies S.E., Pôle d’Etudes et de Recherche de Lacq (PERL); V. Richon, TotalEnergies EP Norge AS, N. Passade-Boupat, TotalEnergies S.E., Pôle d’Etudes et de Recherche de Lacq (PERL)
ABSTRACT
In this paper we present an experimental study on flow instabilities in three-phase flow in a pipeline-riser system conducted at the SINTEF Multiphase Flow Laboratory at Tiller in Norway. The purpose of the study was to obtain a better understanding of the origin of instabilities in deep-water production systems, and how free water affects these instabilities.
The experimental results show that:
- The system is always stable for sufficiently low or high liquid rates, but unstable for intermediate liquid flow rates.
- Large gas volumes upstream of the riser have a strong destabilizing effect.
- Three-phase flow is more unstable than two-phase flow.
The experiments were simulated using LedaFlow Slug Capturing, and the simulation results were found to be in good agreement with the experiments.
Session 8 – Advances in modelling
D. Biberg, K. Sinkov, M. B. Kirkedelen, SLB Norway Technology Center, Norway;
P. S. Johansson, M. Nordsveen, T. K. Kjeldby, Equinor, Norway
ABSTRACT
Surge wave instabilities during constant production cause major operational challenges in
late-life gas-condensate fields, where low flow rates lead to large surges that disrupt liquid
handling at the outlet. Dynamic simulations show that surges originate from local
instabilities in three-phase stratified flow. To quantify surge risk, we introduce a surge
wave indicator that aggregates local long-wave stability characteristics along the pipeline.
This enables rapid assessment from steady-state simulations and reduces reliance on timeconsuming
dynamic simulations. The indicator predicts surge onset at lower rates and
cessation at higher rates, consistent with dynamic simulations and field observations. The
approach provides a practical method for assessing and mitigating surge wave risks in latelife
gas-condensate operations.g.
B. W. E. Norris, S. Sakurai, Z. M. Aman; The University of Western Australia, Australia; P. T. Bhaskoro; PETRONAS Research, Malaysia, G. B. Falope, PETRONAS Centre of Excellence in Subsurface Engineering & Energy Transition, UK; T. Wood, L. Liebana, L. Thomas; Worley, UK.
ABSRACT
In this work we describe a new software tool designed to improve the multiphase community’s ability to simulate Pseudo Dry Gas type subsea separation. This new type of separator is unique in that it is an inline, piggable technology. These features mean that existing separator implementations in packages such as OLGA® are not well suited to describing PDG. Here, we make use of the new Messaging Software Development Kit framework that slb has released for OLGA® which enables third-party software to interface with an active simulation. This is used to build a virtual separator, with efficiencies derived from experimental data.
D. Biberg, K. Sinkov, M. B. Kirkedelen, SLB Norway Technology Center, Norway; P. S. Johansson, M. Nordsveen, T. K. Kjeldby, Equinor, Norway
ABSTRACT
High-quality field data from the decommissioned Y-102 gas-condensate flowline at the Åsgard field revealed a significant underprediction of water content. To address this, an experimental campaign was conducted in Equinor’s high-pressure Porsgrunn laboratory (PLAB) using fluids formulated to replicate field conditions. The updated model improved predictions for both the Y-102 flowline and the Snøhvit gas-condensate trunkline, the latter serving as an independent validation case excluded from model development. A polydisperse model for oil-water dispersion was also introduced by adapting a convection-diffusion formulation to the pipe geometry, enhancing accuracy in oil-water flows. Validation against diverse laboratory and field datasets confirms high predictive accuracy across a wide range of conditions.
J. Trujillo, Galp; S. Morgadinho, Galp; M. Ferreira, Galp; E. Quintos, Galp; E. Barros, Galp; P. Bacelar, Galp.
ABSTRACT
As offshore oil and gas production advances into ultra-deepwater fields (>2000 m), accurate multiphase flow modelling becomes critical for flow assurance. This study evaluates four multiphase 1D models—OLGA HD, ALFAsim, Ledaflow, and TUFFP—, in steady state conditions, across varying GOR and CO₂ scenarios, including cases with and without gas lift and WAG-CO₂ EOR. Historical well test data, spanning from early field life to gas breakthrough, supports the analysis. Transient shut-in and restart simulations were also compared using OLGA HD, ALFAsim, and Ledaflow. The findings highlight model differences and underscore the importance of simulation tools for optimizing deepwater production strategies.
M. Montini, A. Di Lullo, A. Tiozzo, A. Della Pietà, Eni S.p.A., Italy; T. Mantegazza, Eniprogetti S.p.A., Italy
ABSTRACT
This paper discusses a proprietary platform (e-fast™) for flow assurance simulation management and its application to a relevant field case.
The platform was fully developed in-house, within Eni’s Engineering department, with the objectives to standardize the internal workflows, manage all the flow assurance simulations, prevent repetitive and error-prone actions, and maximize the usage of expensive software licenses. The platform is also connected to the company digital oilfield historian to support field-related studies. In this latter respect, one important objective is to facilitate the analysis of past performance and address discrepancies between simulated and actual conditions, to identify issues with the physical system or with the models.
The case study presented demonstrates the system’s capabilities and benefits.
Session 9- Fluids and production chemistry Part 2
L. D. Tenardi, B. W. E. Norris, K. Jeong; The University of Western Australia, AU; E. F. May; Future Energy Exports Cooperative Research Centre, AU, P. L. Stanwix, The University of Western Australia, AU.
ABSTRACT
Many impurities commonly occurring in natural gas streams can, under certain conditions, form solids that accumulate on pipeline walls and ultimately risk blocking the pipeline. Water is a particularly problematic impurity for offshore natural gas production, as sub-sea pipelines often have temperature and pressure profiles within hydrate equilibrium conditions, and cooling of natural gas during processing and cryogenic liquefaction can freeze even trace quantities of water. In this work, we present the design and demonstration of a new in-line solid deposition (ISD) pipeline sensor. It was installed on an experimental pilot-scale gas expansion flowline in which natural-gas hydrates could be formed under flow and up to the point of pipeline blockage. Using the ISD sensor, it was possible to monitor the entire blockage process, from condensation of water, onset of hydrate solid deposition, build-up over time, and blockage. The performance and applications for this sensor are discussed.
S. Simon, Ugelstad Laboratory, NTNU, Norway; G. H. Sørland, Anvendt Teknologi AS, Norway; R. Belt, TotalEnergies, PERL Lacq, France; N. Passade-Boupat, PERL Lacq, France; V. Richon, TotalEnergies EP Norge AS, Stavanger, Norway
ABSTRACT
The type of emulsion obtained when oil and water were mixed at various water cuts was determined and the stability and features of formed emulsions were determined by new NMR procedures.
This paper will explain how NMR has been used to study the transition between a water-in-oil (w/o) to an oil-in-water (o/w) emulsion, demonstrating the relative concept of saturation point rather than inversion point. Indeed, emulsion inversion from w/o to o/w was observed only when mixtures of hydrophobic and hydrophilic surfactants were present. With only hydrophobic surfactant (like crude oil), transition from w/o emulsions to a phase separation between pure water and diluted w/o emulsion happened at a saturation point. Below the saturation point, the emulsions showed hindered sedimentation, and, above, the diluted w/o emulsions destabilized rapidly, even if there was enough surfactant to cover droplets.
Session 10- CO2 transport and storage
R.A.W.M. Henkes,Delft University of Technology and Shell Projects & Technology, The Netherlands; J.E. Ellepola, and A. Rao, Shell Projects & Technology, The Netherlands
ABSTRACT
CO2 capturing, transport, and storage will play a key role in the energy transition. Therefore, quite a few technology developments are underway to obtain the proper design tools for this. A particular challenge is the simulation of CO2 under two-phase flow conditions with fast transitions at depressurization or with fluid hammer effects after opening or closing of valves. A specific operational concern is the risk of “vapour collapse” when dense CO2 falls on top of a vapour column in an injection well to a low-pressure reservoir, when the well head choke is opened after shut-in. Recently, lab experiments were carried out by Exxon and IFE to investigate whether vapour collapse for CO2 is a real risk; it is concluded that the risk of vapour collapse is significantly lower for CO2 than it is for water. However, for the CO2 system design, there still is a desire to quantify the transients. Thereto, the present study gives a detailed analysis of a start-up simulation for a full-scale configuration using the start-of-the-art tool OLGA. This tool is one-dimensional and assumes full local equilibrium. The results reveal some shortcomings in the capabilities of the 1D full equilibrium approach when assessing fast transients after opening of the well head choke valve at start-up of a CO2 injection system. Only pure CO2 is considered, which is numerically more challenging than CO2 with impurities.
H. Nemoto, A. Brigadeau; SLB, Norway Technology Center, Z. Yang; Equinor ASA, Norway, L. Rønning, T. Vincent-Dospital, J. Ø. H. Bakke; SLB, Norway Technology Center
ABSTRACT
Reliable simulation tools for multiphase CO2 transport are crucial for designing cost-effective carbon capture and storage systems. To evaluate available simulation tools and recent advancements, experimental campaigns were conducted emulating typical transient operations such as depressurization, shut-in, and restart. Two solvers in a commercial dynamic multiphase flow simulator were evaluated against the experiments: the standard solver, which resolves momentum and energy equations separately, and the new solver, which resolves them concurrently. The new solver exhibits superior accuracy and numerical stability in handling rapid phase changes, associated with narrow phase envelopes in systems dominated by a single component, such as CO2 transport.
Session 11 – Data analytics in operations
M. Nordsveen, A. A. Ayati, Equinor ASA, Norway
ABSTRACT
This work re-analyses field data from the Heidrun oil field. The production is tied back from a subsea template through a 4.5 km long 10-inch near-horizontal pipeline and
a 400 m vertical riser.
The identified flow regimes include wavy-stratified flow, hydrodynamic slugging and terrain slugging. The hydrodynamic slugs were found to consist of low and high mixture density zones, indicating that shorter Taylor bubbles are entrained into the slugs in the riser.
Terrain slugging occurs at low pressure and high flow rates, coinciding with stratified flow near the slug flow boundary in downhill sections of the pipeline.
T. Newnham, Pontem Analytics, UK; A. Yule, Pontem Analytics, USA; A. Priyadarshi, Pontem Analytics, UK; I. Kopperman, Pontem Analytics, UK
ABASTRACT
Wax deposition is a persistent challenge in subsea pipelines, particularly in systems experiencing declining production and reduced temperatures. Traditional wax management relies on paraffin inhibitor injections and periodic pigging, both of which can be expensive. Additionally, late-life pigging becomes particularly challenging due to reduced flow rates and velocities. Further, real-time quantification of deposition remains a key industry challenge.
This study presents a hybrid approach, integrating physics-based thermal-hydraulic simulations, with data-driven system monitoring, alongside laboratory fluids analysis to assess wax deposition risk dynamically and in real-time operations.
Utilising physics informed machine learning and laboratory wax characterisation, the model successfully identified deposition trends and optimised chemical dosing and operating strategies. Key insights include:
- Continuous Monitoring: Pressure, flow and temperature trends aligned closely with model predictions, allowing early detection of minor deposition while confirming no significant flow restrictions.
- Predictive Insights: The model allowed quick estimation of wax deposition along the pipeline utilising a hybrid data driven & physics-based approach.
This approach has been applied over several years of operation to this specific, non-piggable, asset to enhance production following an ESP failure which led to flowing temperatures below the WAT. The hybrid monitoring system enabled proactive wax management without pigging and was essential to reduce operational risks and optimise chemical usage. The findings demonstrate the value of integrating real-time field data with predictive analytics and physics-based modelling to improve subsea pipeline performance and longevity. This can be applied to any operating system, with machine learning assisting in moving away from an expensive all-encompassing physics-based digital twin. This case study utilises a use-case specific digital twin based on data analytics and physics informed machine learning for wax monitoring.
L. Hagesæther, S. B. Joramo-Hustvedt; Equinor ASA, Norway, Gupta, M. Espeland, C. Trudvang, R. Colmenares; SLB, Norway
ABSTRACT
In this paper we provide a comprehensive evaluation of the operational experience and performance of the multidimensional leak detection system (LDS), which is operational in the Johan Sverdrup (JS) multiphase pipelines. The primary goal of LDS is to ensure reliable early leak detection, thereby minimizing environmental impact and enhancing pipeline operational safety. Experiences described in this paper demonstrate the business value of the LDS for the operator companies and the technology suppliers.
This multidimensional LDS has proven to be robust as the number of avoidable false leak alarms is less than two per pipeline per year since deployment, with system annual availability higher than 99%.
Session 12 – Multiphase flow
T. R. Gessner, O. M. França Jr, T. G. M. dos Santos, Petrobras, Brazil
ABSTRACT
In this study, we developed a simple and easy-to-use flow model to represent the circulation of diesel and seawater in subsea pipelines. Simulations of this type are important to predict pressure trends at the service pump and other key points in the system, determine the minimum time for the displacing fluid to return to the surface, and estimate the volume of original fluid that will remain in the circuit. The proposed model presents a one-dimensional steady-state mechanistic formulation coupled with a pseudo-transient approach that combines the solutions obtained at the beginning and at the end of cleaning operations to reproduce its dynamic behavior. A performance evaluation conducted in two Petrobras Offshore Production Facilities (OPFs) using the new tool and two leading commercial simulators indicated that the former incurs slightly higher residual volumes, which is desirable from a safety perspective, while the calculated pressure trends reproduced the available field data with good accuracy.
A. Soedarmo, Z.G. Xu, T. Brenna, I. Koshelkov, J. Sogn, K. Sinkov, S. Dayarathna, L. Rønning, SLB, Norway
ABSTRACT
This paper presents a novel 1D model to simulate developing hydrodynamic slug flow in pipelines by applying a statistical ensemble average concept. The model offers noticeable speed-up benefits over the state-of-the-art model for this application. The new model is tested against more than 300 developing slug flow datasets (comprising both field and laboratory cases) and achieves comparable accuracy to the state-of-the-art model in predicting mean slug length and slug frequency.
C. Chauvet & M. J. Watson, Wood PLC
ABSTRACT
Fully understanding the multiphase flow regime in a pipeline network is often very challenging, especially when the flow behaviour transitions from one regime to another due to flow splitting. This challenge is exacerbated when the multiphase flow split is not fully understood, leading to scenarios where one part of the network receives more gas while another is filled with liquid. Although pipeline engineers strive to design the branches downstream of the split as symmetric as possible, space constraints or a lack of understanding of the complexity of multiphase flow dynamics can result in significant unbalanced flow between the branches.
Numerical tools used to simulate multiphase flow behaviour can be divided into two categories: 1D software, which relies on the fully developed flow assumption, and 3D tools, which explicitly solve the Navier-Stokes equations. In the context of a multiphase flow split within a network, the 1D solver will only consider the pressure balance within the different branches but ignore the flow dynamics that cause the maldistribution of phases at the split. In contrast, the 3D model accounts for the local details of the flow path around the split area and the flow dynamics to determine a more accurate flow split of each phase but is limited in terms of the length of the pipeline included in the model.
The application of 1D and 3D tools to a range of cases was carried out, inspired by real-life examples, giving some practical insight into their applicability to this perplexing phenomenon.
P. Sassan Johansson, A. Valle, F. Könz, T. Kindsbekken Kjeldby; Equinor, V. Richon, R. Belt; Total Energies, O. J. Rinde, A. Vestvik; Gassco
ABSTRACT
Flow loop experiments with high flow rates and low liquid loading have been conducted using natural gas, Troll condensate, and a MEG/water mixture. Scans with varying water-cut, gas flow rate, and liquid loading show complex behaviour with respect to pressure drop. For example, a water-cut scan may show pressure gradients that vary by more than 100% for the same gas and liquid volume flow rates. To explain the observed pressure drop trends for two-phase flow, three contributing mechanisms are presented. For three-phase flow, four different flow regimes are suggested: the thick condensate layer, moderately thick condensate layer, thin condensate layer, and disintegrating condensate layer. The mechanisms behind these hypotheses are explained and subsequently used to interpret the experimental results.
