Transient multiphase pipeline simulators are seeing increasing application for live computation of oil and gas production pipeline and process flows. This study considers the performance of Wood Group’s Virtuoso tool and three other commercially available simulators used widely in the industry, on an extended set of field data from a large gas-condensate pipeline with three-phase flow. A steep escarpment strongly influences the dynamics of pipeline pressure, and liquid content and outlet rates; production rates span the region of transition between separated and slug flow regimes. ‘Out-of-the-box’ model predictions of pressure drop can differ from measured values by 20% or more. While model predictions of liquid holdup agree reasonably well - both mutually and against experimental data - for small-diameter pipes at gentle inclination, predictions vary by 50% or more under field conditions. The extent of scatter in predicted holdup is a large fraction of available slug catcher capacity. Analysis indicates that pressure and liquid volume predictions are sensitive to flow regime determination, specifically via the interfacial friction factor and the holdup at which slugging initiates; pressure prediction error can be reduced by 50% through moderate adjustment of associated modeling parameters. These aggregate assessments of model performance suggest that field-specific model tuning remains necessary to achieve the level of prediction accuracy demanded by online systems used for liquids management, forecasting, and pipeline integrity monitoring.
Simulation tools are used extensively for the design and for the improved operations of oil and gas production systems. Most of these simulations are carried out with steady and transient one-dimensional tools, such as PIPESIM, OLGA and LedaFlow. For some applications, however, such as flow in bends, flow in splitters, flow in headers to facilities etc. the one-dimensional assumption limits the prediction accuracy. As an alternative, Computational Fluid Dynamics (CFD) can be used, either for two-dimensional and three-dimensional configurations. The study as presented in this paper is focused on the verification and validation of CFD results for multiphase flow of gas and liquid through vertical pipe sections. The open source CFD framework OpenFOAM has been used for this purpose, employing two different multiphase flow methods. The Volume of Fluid method can be used for the capturing of the liquid-gas interfaces, while the two fluid model approach is typically used for dispersed phases. In the present study these two models were combined in a hybrid model and validated using two representative test cases for the vertical pipe. For these two test cases CFD and experimental results are available in the literature, particularly results with Fluent, as presented at a previous BHR conference , and with Star-CCM+ as presented in .
Multiphase flows remain an area where the prediction through CFD (Computational Fluid Dynamics) is yet out of reach for the majority of applications. Multiphase flows are characterized by a broad range of scales, from the dispersed droplets at the micro scale up to macro scale free surface flows.
Nossen, J. (Institute for Energy Technology (IFE), Norway) | Liu, L. (Institute for Energy Technology (IFE), Norway) | Skjæraasen, O. (Institute for Energy Technology (IFE), Norway) | Tutkun, M. (Institute for Energy Technology (IFE), Norway) | Amundsen, J. E. (Institute for Energy Technology (IFE), Norway) | Sleipnæs, H. G. (Institute for Energy Technology (IFE), Norway) | Popovici, N. (Institute for Energy Technology (IFE), Norway) | Hald, K. (Institute for Energy Technology (IFE), Norway) | Langsholt, M. (Institute for Energy Technology (IFE), Norway) | Ibarra, R. (Institute for Energy Technology (IFE), Norway)
Annulus flow commonly occurs in oil wells where well fluids flow between an inner and an outer pipe in the well. An extreme example is the Macondo accident. Although annulus flow is common in drilling, production and well intervention, our understanding of multiphase annulus flow is rudimentary compared to flow in circular pipes. The present knowledge is based on small scale, low pressure studies, mostly for vertical flow. Even this sparse knowledge is hardly built into commercial simulators. A new project is currently undertaking experimental and numerical studies of the fundamental physics of annulus flows. A new six-camera X-ray tomography system is mounted on IFE’s Well Flow Loop and used to reveal internal flow structures for a wide range of gas-liquid and oil-water flows. The initial campaign is reported in the current paper.
On the 20th of April 2010, explosion and fire killed 11 people on the Deepwater Horizon oil rig in the Gulf of Mexico and began a human, economic and environmental disaster. After two days in flames, the rig sank and left the drilling riser on the sea floor leaking oil and gas from the well through the gap between the riser and the drill-string.
Immediate concerns were raised regarding the amount of oil being discharged to sea, and this number has also played a significant role in the legal proceedings. One of many techniques that were applied was based on using a multiphase flow simulator to match the observed slug frequency out of the sunken riser. There are, however, serious flaws to this approach, the most apparent being the lack of reliable multiphase flow models for flow in annuli, that is, flow between the inner and the outer pipe. Commercial multiphase flow simulators lack the ability to correctly predict pressure drop in annulus flow, even for single phase flow. Well design is thus based on crude assumptions with large uncertainty and high error margins. This may lead to inefficient well design and high risk of production problems.
Liquid loading is the mechanism that is associated with increased liquid hold-up and liquid back-flow at lower gas flow rates in gas production wells. In the laboratory, most liquid loading experiments are performed at fixed gas and liquid rates (mass flow controlled). In the field, the well behaviour is a coupled well-reservoir system in which the reservoir results in a pressure or mass flow controlled inflow, depending on the reservoir characteristics. In this paper, results are presented for experiments which have been performed with a pressure controlled vessel attached to a vertical pipe. The pressure drop was varied to represent reservoir characteristics from tight to prolific. Liquid was injected using a mass flow controller.
From these experiments, it was concluded that the flowrate at which loading occurs can be predicted by the overall pressure drop curve. That is the pressure drop from vessel to separator and not the tubing pressure drop curve. A numerical investigation confirms this for pressure dependent liquid injection. This stability point can be at a higher or lower velocity than the actual loading/flooding point. The results of these experiments are elaborated briefly. The main focus of this paper is the evaluation of the influence of external disturbances on stable flow conditions. A stable system is defined as a system in which the conditions are such that gas flow is possible and will not stop. At unstable conditions, the gas flow starts to drop. In the experiments described in this paper, it was found that the required external disturbance to destabilize a system is related to the pressure drawdown.
Barton, L. (ROSEN UK, Corrosion Management Group, UK) | Forde, M. (ROSEN UK, Corrosion Management Group, UK) | Pinto, A. (ROSEN UK, Corrosion Management Group, UK) | Laing, I. (ROSEN UK, Corrosion Management Group, UK) | Ladwa, R. (ROSEN Group, Flow Assurance, Switzerland)
Using corrosion rate predictions, from either direct measurements or calculated corrosion rates, is not a new or novel approach. Both of these approaches have their own advantages and disadvantages. Corrosion, is a main pipeline degradation mechanism, and therefore understanding its effects, greatly improves integrity planning. Direct measurements can be more accurate compared to corrosion modelling, due to the dynamic variability of corrosion reaction kinetics, which corrosion models cannot account for. However, direct inspection is not always achievable, therefore engineers are forced to rely on the calculations of corrosion models.
In this work, the predictions of a selection of sweet corrosion models against actual corrosion rates in multiphase pipelines will be discussed. Subsequently, the benefits and limitations of flow modelling to improve corrosion predictions will be demonstrated.
In an ever more cost conscious economic environment, the importance of modelling and prediction of pipeline degradation has a much larger part to play in effective Asset Integrity Management (AIM). Cost-effective inspection intervals, avoiding un-necessary repairs and overall extending the asset life without compromising safe operation, is the ultimate goal of modern AIM systems (1). Historically, integrity management was based on direct inspection and operation, as part of “data gathering” for the specific asset and could be considered a learning cycle and the AIM system is then developed in a reactive way. The problem with reactive methodologies, which have trial and error or practical learning at their core, is the associated cost. As there must inherently be some form of failure or shortcoming before actions can be conducted, or implemented. Therefore, having the ability to account for likely future scenarios, and plan accordingly, negates the need for repetitive reactive practices and consequently reduces costs.
Risk and uncertainty play an important role in design and operation of complex oil and gas production systems. They are also a driver for business decisions and can have significant implications on capital and operational expenditures (CAPEX and OPEX). A thorough understanding can lead to flexible strategies with mitigations that can limit downsides and capture unexpected upsides. While there has been significant focus on risk and uncertainty in the subsurface (1,2), application of such approaches for flow assurance design and operation has lagged. The work here details concepts and methodologies for evaluating uncertainty from fluid property measurement, to model application, in order to drive risk based decisions. A case study for production application is presented demonstrating the importance throughout the life cycle of an asset.
The evolution of uncertainty assessment and its impact on decision making is rooted in several disciplines dating back several centuries. For example, scenario based planning is used by the military for civil defense, the scientific community for articulating complexity, policy makers for assistance in policy implementation, professional or academic futurists and businesses for long range planning (3). In the oil and gas industry, articulation of uncertainty and long range business planning are critical to success and therefore such approaches have been adapted. One of the earliest adaptors of such approaches was Royal Dutch Shell in the late 60’s (3) and as the discipline continued to develop it has been adapted by many others within many industries, including oil and gas. Goode (4) had estimated that US$30 billion in expenditures is lost by the oil and gas industry each year due to poor decisions. While statistical analysis, computing power and advanced algorithms have improved, Bickel and Bratvold (5) stated that based on their data collected from ~500 oil and gas professionals, that more information/data has not made the industry better at making decisions.
The Prelude Floating Liquefied Natural Gas (FLNG) project is due for first gas in 2017 and other projects are in the pipeline to take up the FLNG concept. These indicate that FLNG is now seen as a viable solution to access remote gas resources, of varying size, avoiding the infrastructure expenditure associated with long gas transmission pipelines and onshore processing and export facilities.
A number of other developments are considering the FLNG concept for gas development due to the perceived simplicity from design, control and operability perspectives. FLNG however, brings with it many challenges and when detailed engineering commences it can feel like opening Pandora’s Box. Design and operability issues are driven by the proximity of complex reservoir behaviour and the intricate processing equipment associated with offshore FLNG which, amongst others, can regularly lead to production disruption and complex operability issues.
The paper provides an overview of FLNG, its potential challenges and the associated solutions, so you end up with the Holy Grail rather than Pandora’s Box.
1.1 Floating Liquefied Natural Gas (FLNG)
FLNG is a floating facility that will produce, liquefy, store and transfer LNG (and usually condensate) at sea. FLNG is a new enabler in the production of natural gas, particularly when considering remote locations and ‘new frontiers’ for gas reserves. However, development of such facilities is not without its challenges, particularly from a process, flow assurance and multiphase flow stand-point to ensure the operability and full understanding of the CAPEX and OPEX requirements and potential impacts.
Low liquid loading conditions in wet gas pipelines are challenging to characterize due to a lack of high quality field data and potential for multiple numerical holdup solutions. Recently, experimental and modelling activities have been conducted to improve the accuracy of multiphase flow simulation tools for low liquid loading conditions. The outcomes of this research were implemented and tested in the LedaFlow simulator (v2.0).
This paper presents the validation and comparison of two versions of LedaFlow (v1.8 and v2.0) using operational data from an offshore gas condensate field. The field measurements consisted of pressure, temperature and mass flow rates, which were recorded during quasi steady state flow conditions and transient production scenarios, such as ramp-down, ramp-up, shut-in, restart, and pigging of a three-phase, large diameter pipeline system.
The predicted pressure, temperature and mass flow rates are in good agreement with the field measurements, regardless of the software version used. Prediction of the large diameter pipeline liquid content, validated by measurements inferred from the pigging operations, improved from version 1.8 to version 2.0.
The development of gas-condensate production systems and, more recently, the emergence of long subsea tie-backs to existing facilities, have been driving studies of multiphase flows at low liquid loadings in near-horizontal pipes over the past years.
van 't Westende, J. M. C. (TNO, The Netherlands) | Henkes, R. A. W. M. (Delft University of Technology and Shell Projects & Technology, The Netherlands) | Ajani, A. (The University of Tulsa) | Kelkar, M. (The University of Tulsa)
This paper compares three recent different independent research projects on experiments and modelling of the use of surfactants to create a foam for deliquification of wet gas wells. The research groups involved are TNO, Delft University of Technology and the University of Tulsa. The various experimental setups that are used and their outcome (trends and correlations) are described. In each project, a model was developed to predict the pressure gradient under foam flowing conditions. These models are discussed here and they are applied to representative well conditions.
Liquid loading is a well-known problem that occurs when wet gas wells approach their end-of-life. Due to the depletion of the reservoir, its pressure decreases. Consequently, the gas flow rate in the well is also reduced. When only dry gas is present in the well, the reduced gas flow rate has no further effect. However, when a liquid phase is present (condensate and/or water) the reduced gas flow rate may, at some point, no longer be effective in transporting the liquids to the well head and they will accumulate downhole; this is the so-called liquid loading or liquification. The critical gas velocity, Ucrit, where the pressure gradient is minimized with respect to the gas flow, is often used to determine the onset of liquid loading.
Electric Submersible Pumps (ESP) are widely used in the oil industry to lift the oil production to the surface. ESPs can handle a wide range of flow rates from 200 to 90,000 bbl/d (32 to 14,309 m³/d), and lift requirements from virtually zero to 10,000 ft, (3,048 m), of lift. ESPs can be located in vertical, deviated, and horizontal wells.
To make an optimal design and operation of ESP, it is beneficial to be able to simulate the steady state and transient thermal-hydraulic behaviour of the ESP system including the well tubing, the reservoir and the wellbore. Simulations will help to select the materials for the ESP design so that they can withstand the change of pressure and temperature the pump is subjected to in various operation scenarios. The simulations can also help design operation procedures to ensure operation within the design constraints of the ESP that is installed in the well.
This paper presents the modelling of ESP in a transient multiphase flow simulator. A simulation model is built based on a real well data to calculate the well inflow performances in normal operations and transient operations. The calculated ESP pump speed, suction pressure, discharge pressure and flowrate of different fluid phases in the normal oil production and the transient during shut-in/start-up operations match the measured data fairly well.
Further on, the numerical code is to be used to predict the ESP performance on more scenarios to check the dynamic behavior of the ESP under certain steady state and transient operating conditions in order to ensure the proper guidelines on ESP system components qualification process, the effects of shut-in and start-up on the ESP pump material selection e.g. sealing material, bearings, etc. A comparison of the measured and the calculated data will be used to develop the highly reliable ESP system.