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.
Asphaltene precipitation and deposition is a major flow assurance challenge, which manifests itself in reservoir, production tubing, and flowline and process facility. Asphaltene may unstable and precipitate due to two main factors, namely high asphaltene content, and high difference between reservoir pressure and oil bubble-point pressure, i.e. precipitation driving force. 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.
At high gas rates, even small amounts of liquid can have a significant impact on the pressure drop, and this is important to model accurately when designing wet gas transport systems. In order to gain an improved understanding of this matter, several sets of two- and three-phase experiments in low liquid loading flows with high gas rates were conducted in the Large Scale Loop at the SINTEF Multiphase Flow Laboratory. The experiments were conducted in both a near-horizontal 8" pipe, and a vertical 4" pipe, where particular emphasis was put on studying the effect of water cut. The measurements show that the frictional pressure drop is very sensitive to the water cut in these circumstances, even though the estimated liquid content is typically less than 1%. For instance, at 50% water cut, the frictional pressure drop in the near-horizontal 8" pipe was found to be up to 30% higher than in the respective two-phase scenarios. In the vertical 4" experiments the three-phase effects were found to have similar magnitudes. To explain these surprising results, the physical mechanisms that may be responsible for this phenomenon are briefly examined and discussed.
Figure 1 and Figure 2 show examples of the observed behaviour in the 4" vertical pipe, where the frictional pressure drop divided by that measured for two-phase gas-oil is plotted against the water cut and the liquid rate. These experiments and the associated measurements are described in more detail in the following sections.
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.
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)).
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.
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.
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.
An experimental investigation has been carried out to analyze the effect of the diameter on two-phase flows in vertical large-diameter pipes. This study generated and gathered experimental data for diameters ranging from 19 to 297 mm. The working fluids for the experimental database are water and air, for superficial liquid velocities ranging from 0.2 to 0.7 m/s, and superficial gas velocities ranging from 0.1 to 30 m/s.
From the experimental observations of flow regimes in diameters larger than 97 mm, churn flow is observed under conditions that slug flow would be expected in smaller diameter pipes. The experimental data indicate that the holdup and pressure gradient is systematically higher for the 297 mm pipe, compared to the smaller diameters, when the total pressure gradient is gravitationally dominated. However, the total pressure gradient only changes approximately 25% for pipe diameters ranging from 97 to 297 mm and superficial gas velocities lower than the minimum point in the pressure gradient curve. In contrast, the liquid holdup varies up to 100% for the same range of pipe diameters and gas/liquid velocities. The measurements of liquid holdup and pressure gradient are also compared to a simplified model based on the Drift-flux concept. The results from this simplified model shows that the liquid holdup can only be roughly estimated, however, the pressure gradient predictions stay mostly within 25% of the experimental data.