Setyadi, G. R. (TechnipFMC, Norway) | Holmås, K. (TechnipFMC, Norway) | Lunde, G. G. (TechnipFMC, Norway) | Vannes, K. (TechnipFMC, Norway) | Sengebusch, A. (TechnipFMC, Norway) | Nordsveen, M. (Statoil, Norway) | Pettersen, B. H. (Statoil, Norway)
An online Flow Assurance Simulator (FAS) has been developed for the Åsgard subsea compression (ÅSC) system, which boost the production from the Mikkel-Midgard gas condensate fields. The production is tied back to the Åsgard B platform. The FAS, which is configured in Watch FlowManager™, provides information of the operational process and multiphase flow conditions through the wells and templates, subsea compression station, import/export flowlines and topside separation system.
The flowline model in the FAS has been tuned against existing field data on pressure drop and liquid accumulation. At low flow rates, liquid surge wave instabilities in the flowlines occur. In the present paper, it is shown that the tuned flow model capture these surge waves. The model predicts that the water surge comes from the riser, while the condensate surge comes from the flowline. Details of the predictions of surge build up and release are given.
The FAS is a production operation and planning tool mainly used by Åsgard operational support for liquid management and hydrate control. To demonstrate the FAS performance during a real-time operation, a comparison between the FAS and the field measurements during a restart after a system turnaround is presented. It is shown that the Åsgard FAS captures the transient behaviour quite well.
Field data are presented for two parallel risers connected to the same inlet. The data show that the multiphase flow is split equally over the two risers at high flow rates; however, below a critical flow rate the system diverges: the flow passes preferentially through one riser, and the other riser accumulates liquid. This unequal split is unwanted from the operational point of view, as it leads to a larger pressure drop over the risers and liquid accumulation in one riser. The instability is also studied in a design study of a gas-condensate field with 1D simulations. It is shown that the 1D simulations reproduce the maldistribution of the liquid content of two parallel flowlines. Based on the simulations, an explanation is proposed for the occurrence of the unequal split.
The sizing of a gas-condensate flowline is mainly driven by two constraints. The first constraint is that the pressure drop over the flowline at the highest or “nominal” flow rate must be as small as possible, in order to have the smallest possible backpressure on the wells and therefore the largest production. This constraint imposes to choose a flowline diameter as large as possible to reduce the gas velocity and the wall friction. The second constraint concerns low flow rates: at small gas velocities, the gas exerts a small drag on the liquid layer, and because of gravity the liquid content becomes large in upward sections of the flowline. A large liquid content promotes in turn large liquid surges due to flow instabilities or ramp-up and pigging operations, and therefore the need of large and expensive receiving facilities at the outlet of the flowline. Additionally, a large liquid content increases the pressure drop over the flowline due to the static head. Therefore, the second constraint imposes to choose a flowline diameter as small as possible to have sufficiently large gas velocities in the flowline. The two design constraints are contradictory: a large diameter will give a smaller pressure drop, i.e. a larger production at the nominal flow rate, but it will require larger receiving facilities at low flow rates or a higher production cut-off. Thus, the sizing of a gas-condensate flowline requires determining the optimal diameter of the flowline and the optimal size of the receiving facilities with respect to the operational flexibility and the economics over the life of the field.
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.
In slug flow modelling, the shear stress between the slug body and the pipe wall is one of the critical parameters to define the frictional pressure drop. Experiments were carried out in a 50.8-mm ID horizontal flow loop to identify the trend of the wall shear stress within the slug body for liquid viscosities of 0.51 Pa·s and 0.96 Pa·s. A new setup allowed accurate assignment of the signals from the Constant Temperature Anemometry (CTA) to the corresponding positions in the slug body. Experimental evidence shows that arrival of the slug fronts do not indicate an immediate increase in the wall shear stress at the bottom of the pipe.
Slug flow is a commonly encountered gas/liquid two-phase flow pattern in pipelines. In slug flow modelling, the shear stress between the slug body and the pipe wall is one of the important parameters for the estimation of frictional pressure drop. In many of previous modelling studies such as Dukler and Hubbard (1), constant wall shear stress values are predicted, and applied to develop and validate models. A more adequate wall shear stress measurement is required to investigate the possible effect of wall shear stress changes within the slug body. Additionally, the observation contributes to the analysis of eddy length in the mixing region, Nicholson et al. (2).
In production system design, it is crucial to predict the slug characteristics correctly based on fluid properties and operational conditions. In predicting flow features, viscosity appears as an intrinsic variable in almost all slug flow models. These models are developed for low viscosity fluids. However, two-phase slug flow can exhibit significantly different behaviour for higher viscosity oils as reported by Gokcal et al (3), (4), Kora et al. (5), Brito et al. (6) and Kim (7).
Hendrix, M. H. W. (Delft University of Technology, The Netherlands) | Ijsseldijk, H. P. (Delft University of Technology, The Netherlands) | Breugem, W.-P. (Delft University of Technology, The Netherlands) | Henkes, R. A. W. M. (Delft University of Technology and Shell Projects & Technology, The Netherlands)
In this study we investigate the development of a speed controlled pig in a low pressure pipeline. This is known to be a challenge due to the compressibility of the gas which can induce velocity surges of the pig. In order to reduce these velocity surges, a speed controlled pig with active by-pass control has been designed, fabricated and subsequently tested on a laboratory scale. The experimental setup consists of a 52 mm diameter pipe with a length of 62 meter. The working fluid is air. The speed controlled pig has an adjustable by-pass valve which can provide the right amount of by-pass to regulate the by-passing fluid force. First test runs show that the velocity surges can indeed be reduced, which demonstrate the feasibility of realizing fully autonomous control for bypass pigs in low pressure pipelines.
Pipeline maintenance in the oil and gas industry is usually done with a so-called ‘pig’, which is a cylindrical or sometimes spherical device travelling through the pipeline while being propelled by the production fluids [8, 10]. Such pipelines can transport oil/water, dry gas, or multiphase flow such as gas/condensate/water.
When operating under low pressure conditions, while the flow is gas-dominated, the compressibility of the gas may lead to an unsteady, oscillatory motion of the pig through the pipeline. This is because compressed gas pockets may build up behind the pig when it is moving slower due to for example irregularities in the pipe diameter. When the pressure build-up in such a pocket is sufficiently high, it is able to catapult the pig, resulting in high pig velocity excursions. This can lead to an unsafe and inefficient pigging operation. It can even result in a so-called ‘stick-slip motion’, where the pig slows down completely after a period of high velocity. Apart from possible damage that can occur to the pipe or the pig, velocity excursions may have an adverse effect to the quality of the inspection data that are collected during an intelligent pigging run [9, 11]. It is therefore desired that the velocity of the pig is controlled in low pressure gas-dominated pipelines.
Slug flow continues to be a disruptive influence on both design and operation of multiphase pipelines and risers. In the past, the focus was largely on slugging cycles driven by the riser or driven by large scale terrain effects which were ultimately accommodated through slug catcher design, gas lift deployment, passive or active slug control measures. The current challenge is to resolve the much higher frequency hydrodynamic slug flow in order to support fatigue analysis within mechanical design of free spans, and risers, which have low tolerance to cyclic loads.
This paper will examine the use of tools capable of predicting the formation of hydrodynamic slugs within a production system and following their evolution with length and interaction with terrain. The challenges of routine deployment of such methods in support of design or operations will be considered.
In the past, the need for modelling slug flow was largely focussed around modelling severe slugging cycles and large scale liquid movement events due to restart, ramp-up or pigging, in order that the behaviour could be aligned with the capability of the downstream process plant. Such slugs, and event driven liquid movement, may be accommodated using large vessels, mitigated through operating procedures which change the system in a more gradual manner, or managed using gas injection or other active or passive slug control systems .
The objective of this study is to develop a predictive simulation tool to assess the risk of asphaltene precipitation in oil wells and to estimate the asphaltene risk window. Further objective is to use the developed simulation tool to generate well design and production scenarios to efficiently prevent, mitigate and manage asphaltene precipitation. A comprehensive asphaltene deposition workflow is developed to identify the major steps to enable a solution strategy. To implement the workflow, Ansari et al. (1994) mechanistic two-phase flow hydrodynamic model in vertical wells is coupled with two Asphaltene precipitation thermodynamic models, namely (1995), and Wang et al. (2006). In this study, de-Boer et al. model is extended from a single point reservoir model to a multi-point wellbore model; while Wang et al. is used to predict and compare the asphaltene instability with live-oil instability along wellbore. The developed simulator was validated to predict the risk and depth window of asphaltene precipitation in Middle East oil wells, resulting in a reasonable agreement with the field data. In addition, the simulation tool is used to carry out a parametric study to investigate the impact of oil gravity, and reservoir pressure, on asphaltene precipitation risk.
The subsea gas development in Block 2 offshore Tanzania described in this paper is characterized by water depths of up to 2600 meters and tie-back distance to shore of around 100 km. The seabed outside East Africa consists of deep, large scale canyons and steep inclinations towards shore. The reservoir fluids contain very little condensate and the pipeline flow is typically low liquid loading conditions at high water fractions. The key focus of the work presented at the previous BHR conference in 2015 was related to liquid accumulation. However, this work also revealed that
The key focus of these presentations is hence related to frictional pressure drop in low liquid loading at high water fractions.
To support model development and model verification experiments were conducted in a 4-inch ID 50m-high riser at the Tiller test facility in Norway. The data revealed interesting and unexpected phenomena with respect to frictional pressure drop for high water fractions.
Also, as part of value improvement process the Tanzania project has evaluated replacement of the subsea Wet Gas Meters with a Virtual Metering System only. A study was conducted to evaluate the expected accuracy and uncertainties of a model based Virtual Flow Metering system (VFM) for Tanzania specific operating conditions. Reliable prediction of pressure drop is crucial for such a system.
This paper gives an overview of the Tanzania deep water gas development with focus on the flow assurance challenges relating to a potential subsea to beach concept and the background, motivation and high level results from the conducted work, while the “three-phase vertical flow experiments (SINTEF)”, the model development and verification (Schlumberger) and the Virtual Metering study (FMC) are presented in detail in separate papers.
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.
In subsea processing systems multiphase cooling is required to meet a variety of process needs and flow assurance challenges. Required functionality might include enhanced pipeline corrosion protection, pipeline temperature control, improved process efficiency, compressor anti-surge cooling, gas dehydration and hydrate formation control. The multiphase cooler is an integral building block of the subsea processing station and is now, after the first successful year of operation on the Åsgard Subsea Compression station, a proven technology with a solid track record.
This paper will present the development and qualification of the Åsgard Subsea Compression Station Inlet Cooler. In addition, operational experience and performance data from the first year in service will be analysed and compared to previously qualified CFD tools. The paper will furthermore focus on the multiphase tests carried out during project execution to qualify the liquid distribution philosophy undertaken to guarantee liquid distribution in the cooler inlet header. Significant effort was put into ensuring sufficient MEG distribution to all cooling pipes to avoid hydrate growth under prolonged operation within the hydrate formation envelope. Three phase testing was performed validating the CFD methods used to determine the functionality of the subsea product.
The Åsgard Subsea Compression Station is located about 200 kilometres off the west coast of mid-Norway on the sea floor at a water depth of 260 meters. The station consists of two identical compressor trains receiving multiphase wellstream from the Midgard and Mikkel fields and producing towards the Åsgard B platform. The main purpose of the compressor station is to maintain production above the minimum flow requirement for the pipelines to avoid slugging and thereby increasing the field output by 280 million barrels of oil equivalents.