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.
One-dimensional models of multiphase flow in pipes are based on averages over the pipe cross section, and traditional models rely on bulk velocities, i.e., a single, uniform velocity for each fluid layer. The OLGA HD stratified flow model provides a significant improvement by re-introducing the two-dimensional velocity profile in the pipe cross section.
In this work, we compare the velocity profiles determined by OLGA HD against measured data from two-phase oil-water experiments. Additionally, we will show that good pressure drop predictions can be obtained even when there is a mismatch between calculated and measured velocity profiles over large portions of the cross section.
One-dimensional models of multiphase flow in pipes are based on rigorous balances for the conservation of mass, momentum, and energy in terms of average values over the pipe cross section. While these equations themselves are derived from first principles, closure models (or correlations) are required to address terms related to friction as well as dispersions accounting for the mixing of phases, and these closures introduce a degree of uncertainty into the models. The conservation balances ensure that basic physical quantities are conserved and that they provide qualitatively correct predictions, however, proper friction models are required to produce results that are quantitatively correct.
The OLGA HD stratified flow model was developed to meet the needs for reliable predictions of pressure drop and liquid content in ultra-long gas-condensate pipelines (see Biberg, et al.  for a comprehensive description of the model). To improve predictions over traditional flow models, the concept adopted is to incorporate more physics into the flow description, rather than to rely directly on correlations.
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.
Subsea water removal has emerged as a viable option to prolong the lifetime of brown field installations, increase recovery and generate increased return for operators. This paper presents a thorough literature review of both current subsea liquid-liquid separation installations as well as state of the art technologies currently being developed for field application. The applicability of respective technologies to identified business cases is discussed, including principle of operation, size and efficiency considerations, as well as technology readiness level. The details and layout of a newly constructed oil-water test loop to develop and design compact separators will also be presented.
During an oil field’s operational lifetime, the quantities of produced water in the production stream will steadily increase. Eventually, produced water will emerge as the main extracted fluid, and the rate will steadily increase until production is no longer economically viable. A review of oil and gas produced water treatment from 2009 (1) reported a global produced water production of 250 million barrels per day, accounting to a produced water to hydrocarbon ratio of 3:1. Looking to the NCS (Norwegian Continental Shelf), a total produced water quantity of 190 million m3 was reported for 2015, accounting for more than twice the amount of produced oil (2). This ratio will steadily increase as more fields are reaching their mature stage, and illustrates the need for produced water management.
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.
An experimental study of vertical two-phase flow was conducted at the SINTEF Multiphase Laboratory using a 51 meter long 4" pipe at system pressures of 45 and 70 bara. This campaign was conducted as part of a project aimed at improving the physical models in LedaFlow for near-vertical pipes, and was divided into several parts. The first part was dedicated to liquid loading in wells, and was published in BHRG 2016 . The current paper describes the second part of the campaign, which was focused on liquid dominated steady-state flows in vertical pipes. In order to extract sufficient information about the flow characteristics in the experiments, the pipe was equipped with ten DPcells, nine static gamma densitometers, one traversing gamma densitometer and one dual wire mesh sensor. The experiments covered all the important flow regimes (bubbly flow, slug flow, churn flow and annular flow), yielding a unique and highly relevant data set with detailed measurements. The new data set, combined with data from previous vertical flow campaigns, was subsequently used to derive improved closure laws for LedaFlow, with particular emphasis on the difficult churn flow regime. The new models were found to improve the overall holdup and pressure drop predictions significantly.
Integrity assurance of subsea, onshore and topsides piping components over the life of a field is of prime importance for optimized production. Sand in the produced hydrocarbon fluids can lead to erosion in various components as it is transported from the well to shore. It causes irreversible metal loss and poses serious threat to the integrity of the production system. It is estimated that the sand erosion related issues annually cost operators billions in lost revenue and maintenance.
The effect of erosion and how to litigate it should be addressed at early stages of a project design. To do this effectively the design team will require prior understanding of potential issues regarding erosion. Computational fluid dynamics (CFD) is a very powerful tool to highlight issues regarding sand erosion and identify the most effective ways to mitigate or reduce the impact of erosion. However CFD is a complex and requires specialist resources to obtain reliable quantitative prediction of metal loss in a system. To be effective CFD requires a robust verification process to provide validated results.
INTECSEA /WorleyParsons have developed a robust sand erosion CFD process through in-house testing and independent validation. This process has been effectively used to highlight and mitigate sand erosion related issues in subsea developments. The same process has also been successfully used for development of the Erosion Control Technology (ECT), a patented (WIPO Patent Application No.: PCT/EP2016/066158) technology developed in-house. ECT is a first of its kind erosion control technology to reduce metal loss due to sand erosion by redistributing sand particles in a flow field. CFD was used for designing the test rig and the technology itself.
This paper will highlight the process which has been undertaken in developing this technology and how applying the CFD process can assist in mitigating the sand erosion risk.
Biberg, D. (Schlumberger Norway Technology Center, Norway) | Lawrence, C. (Schlumberger Norway Technology Center, Norway) | Staff, G. (Schlumberger Norway Technology Center, Norway) | Holm, H. (Statoil ASA, Norway)
We consider the apparent roughness and increased pressure drop associated with the presence of a thin liquid film between the gas and the pipe wall in a two- or three-phase separated gas-liquid flow. The main objective is to improve the pressure drop predictions for near-horizontal gas-condensate flows with low liquid loading. However, in this paper, we focus on vertical (fully symmetric) annular flow to isolate the effect of the liquid film. To support the model development, SINTEF conducted experiments in a 4-inch ID 50 m-high riser at the Tiller test facility in Norway. The data revealed interesting and unexpected phenomena for high water fractions. Nevertheless, a new model for the film roughness based on dimensional analysis and simple but fundamental physics is able to give results in very good agreement with the data. The new model also provides a robust estimate of liquid entrainment. All liquid in excess of that which can flow in the liquid film is entrained into the gas phase through the action of interfacial turbulence.
The Tanzania Gas Project aims to exploit reserves located offshore from Tanzania in East Africa. The narrow operational envelope associated with the extreme water depth underlines the importance of accurate flow simulations for design and production. A large data set was sampled at the Tiller high-pressure test facility in Trondheim, Norway in 2013 and 2014, to support the modelling of liquid accumulation in the Tanzania field (Holm (1); Kjølaas et al. (2); Biberg et al. (3); Staff et al. (4); Nossen et al. (5)).
A very simple, low-cost gas-liquid flow meter that only employs conventional field instrumentation has been used to monitor severe slugging occurring at the exit of a vertical pipe. This meter was originally developed for conventional oil field applications  and is based on the readings of a multiphase orifice and the pressure drops of the gas-liquid mixture flowing in a vertical section of the pipe. Liquid and gas flow rates have been determined by means of semi-empirical equations developed for the specific set of flow parameters (geometry, flow rates, physical properties) adopted in a series of laboratory tests conducted in the Multiphase Flow Laboratory of TEA Sistemi. The transient behavior of the flow system, including the orifice, has also been predicted by means of a 1-D flow simulator . The results of these simulations agree well with the experimental readings, thus providing a powerful method to monitor severe slugging by means of low cost instrumentation, in particular, by replacing a cumbersome instrument such as a gamma-densitometer with a differential pressure transmitter. In field operation, the multiphase orifice used in these experiments can be replaced by a calibrated control valve.
The accuracy of multi-phase flow meters (MPFMs) has been and still is disappointing. To some extent, this is due to the complexity of the flow system and to several mechanical or chemical effects, such as solids deposition, erosion and corrosion, that alter the flow conditions inside the meter. On the other hand, the complexity of the flow system would suggest the use of “as simple as possible” MPFMs, but often this is not the case. To give an example, a radioactive source is often deployed to measure the mixture density, but this requires a careful analysis of gamma ray attenuation through the pipe wall and the multiphase stream, introducing several potential errors, and definitely represents a cumbersome device . At the same time, it only provides the measurement of the liquid hold-up, which is related to the non-slip liquid volume fraction by some type of empirical equation.