In the field of oil production and transmission, flows of two-phase mixtures (e.g. gas-liquid mixtures) (hereinafter referred to as “multi-phase flows”) or other mixtures of constituent parts having varying densities (e.g. liquid-liquid mixtures, gas-liquid mixtures, gas-gas mixtures) (hereinafter referred to as “mixture flows”) are commonly encountered. This is especially true in production carrier pipelines conveying oil mixtures from a producing well. Producing wells, for example, may contain a mixture of oil, water and various gases that are extracted as a mixture flow through a pipeline. These flows must be received by oil handling systems and separated into constituent or component parts based on phase or density for treatment and subsequent distribution to end users.
It is often desirable for the separation of the components of a mixture, particularly those of different phases, to occur prior to the transmission thereof through significant lengths of pipelines. Early multi-phase or mixture flow separation enables mechanical devices functioning within oil production and transmission systems to manage component flows each having substantially only one phase or range of densities. Examples of such mechanical devices include compressors utilised for compressing materials in gaseous states and pumps for moving the flow of liquids. By managing component flow of a single phase or density range, these mechanical devices can be engineered for optimum performance while reducing stresses placed on respective oil handling systems. Thus, compressors are normally designed to handle gaseous streams and may be damaged by the presence of liquids. Similarly pumps are normally designed to handle liquid streams and may be damaged by the presence of gasses.
However, multi-phase and mixture flow separation may not be a simple matter. Firstly, many producing wells are positioned at remote locations and in harsh environments, such as on a deep sea floor. In those situations, achieving separate component part flows shortly after the corresponding multi-phase flow or mixture flow (especially two-phase flow) leaves the well requires a separator to be located where it is not easy to install nor easy to access when system maintenance is needed. Further, most conventional systems that achieve efficient component separation may be quite bulky and heavy, reducing the desirability of using such separation systems on offshore platforms where weight and space considerations are a high priority.
In those situations where multi-phase or mixture flow separation is not possible at or near the well site, the oil, water and various gases that are extracted from the well must be transported along pipelines, sometimes over significant distances, before they can be treated.
A fluid flows along a pipeline as a result of the pressure difference between the upstream and downstream ends of the pipe. The flow of a two-phase gas-liquid mixture along a pipeline can lead to an uneven distribution of the components of the multi-phase mixture that interferes with the free flow of the gas and creates undesirable cyclic flow characteristics, referred to as a ‘slug flow’. Slug flow can result in significant increases in pressure drop, and can become a limiting factor in maximising the length of a pipeline, the usable range of flow rate and the minimum delivery pressure of the pipeline.
Slugs can be formed in a number of ways. Liquid may be formed in a multi-phase or mixture flow by condensation as a result of a pressure drop across a well-head choke valve. In addition, multi-phase flow or mixture flow can experience frictional losses and heat losses to ambient temperature as it travels along the pipeline. These changes in the conditions can alter the equilibrium of the components in the pipeline, leading to for instance, gas condensate formation in a partially conditioned gaseous phase and gas flashing in a partially stabilised condensate phase, producing so-called ‘hydrodynamic slugging’.
Slugs may also be formed by other factors such as pipelines which have many changes in elevation. Liquid components can accumulate at the low points of the upward sections of pipelines until the full pipeline cross section at the bottom of the slope becomes blocked with liquid components, forming a ‘terrain-induced slug’.
In addition, a multi-phase flow will form an equilibrium between liquid and gaseous components for a particular flow rate. The liquid component of the flow will have a lower velocity than the gaseous component and therefore a longer residence time in the pipeline. A particular level of liquid or “hold-up” is therefore established in the pipeline. An increase in multi-phase flow, such as when additional well-head manifolds are being brought on-line, will lead to the formation of a new equilibrium between the gaseous and liquid components. The level of hold-up in the pipeline will decrease towards a new equilibrium level, generating surges of liquid, known as ‘flow-induced slugs’ in the process.
As a result of slug formation, surges of components of the multi-phase or mixture flow (e.g. gas or liquid) may occur at any given point along the transmission pipeline, impeding efficient multi-phase or mixture flow and causing increased stresses on mechanical devices of the transmission system.
However, slugs are frequently composed of valuable liquid hydrocarbons, and it is economically desirable to have these hydrocarbons available for processing. Consequently facilities for receiving and treating a slug may be present near the downstream end of a pipeline. One such facility is a ‘slug-catcher’ which can provide a separation of the gas and liquid components of the multi-phase flow before further treatment. The volume of the slug catcher is conventionally dimensioned to collect the largest anticipated slug size.
Pipeline inspection and maintenance may induce unusually large volumes of fluid. For example, a pipeline must be periodically cleaned to remove liquid such as partial condensate, and debris such as sand and pipeline corrosion products, which have accumulated in the pipeline. It is common to introduce “spheres” or “pigs” (hereinafter referred to as “pigs”) into the pipeline to aid in accumulating the liquids and debris into masses, or ‘pig-induced slugs’, which can be pushed along the pipeline ahead of the pig, which is propelled by the flowing gas. The pigging of a pipeline is essential maintenance because it allows periodic inspection and maintenance of the pipeline. In some cases, pigging reduces liquid hold-up in the pipeline and therefore increases the pipeline's capacity for gas flow.
The pigging of a pipeline can produce slugs of significantly larger size than hydrodynamic-, terrain- or flow-induced slugs. This may exceed the handling capacity of the slug catcher and can lead to the tripping of downstream processing facilities. It is not always economic to simply increase the size the slug catcher to deal with pig-induced slugs because pig-induced slugs may be 4-5 times the volume of hydrodynamic-, terrain- or flow-induced slugs.
WO 03/067146 A1 discloses a subsea pipeline for multi-phase flow having an integrated slug-catcher, in which the pipeline has a branch line such that the pipeline and branchline together contain at least one upstream and two downstream ends. The connection of the branch line to the subsea pipeline occurs at a low point of the subsea pipeline and the connection is downwards directed such that the branch line can transport in particular the liquid phase and act as slug-catcher.
WO 03/067146 discloses that the branch line may contain a separator in the form of collecting tanks for liquid. No provision is made for the provision of an overhead gaseous stream from the separator.
EP 0331295 A1 discloses a system for separation of gas, from a two-phase flow of oil and gas, in a secondary riser. The oil and gas is transported in a pipeline having an upstream end connected to an oil well at the seabed. A main riser for transporting oil is connected to an oil storing tank on a platform. A secondary riser is connected via a T-junction to the pipeline at a distance from the main riser and leads to a gas scrubber on the platform. The secondary riser contains a regulating valve which is operated in such a way to keep the interface between the gas and the oil at a relatively constant location in the pipeline between the T-junction and the main riser. The oil and gas are separated at the T-junction, where the gas components pass into the secondary riser and the oil components pass into the pipeline downstream of the T-junction and into the main riser. The pipeline between the T-junction and the main riser is slightly sloped so that a liquid seal is formed in the riser. The regulating valve, by venting the gas, regulates the pressure in the pipeline and in the main riser. The main riser will contain fluid which is 100% oil and the oil/gas interface at all times will be located between the T-junction and the main riser.
However, the system of EP 0331295 A1 is unsuitable for providing a continuous output of gas, for instance during pigging of the pipeline.