Expert Knowledge
Flow Assurance
Flow Assurance: Ensuring the smooth transportation of oil and gas
Definition of flow assurance
ince the beginning of the 1990s the term “Flow Assurance” is used to designate the assurance of oil and gas transport in pipelines. It covers the fields from subterranean or subsea deposits over the drill hole up to the preparation and processing in refineries. These fields comprise versatile tasks and areas of special knowledge.
The newer term “Flow Management” is used parallel with “Flow Assurance”.
Diverse challenges in flow assurance
1. Crude oil consists of more than 1000 different components
Crude oil is a very complex mix of several thousand different hydrocarbons comprising variable amounts of heteroatoms like sulfur, oxygen, nitrogen as well as diverse metalorganic compounds. From soluted gases (hydrocarbons gaseous under standard conditions = atmospheric pressure and room temperature) to heavy substances like resins and asphaltenes it comprises many different fractions, which can be sorted and separated by their different physicochemical properties.
2. Composition differs from deposit to deposit
From deposit to deposit large differences in the composition of crude oil can be observed. The variety of conveyable oils spans from straw-coloured, low viscosity oils to deeply black, heavy oils. This can lead to different viscosities, densities and phase behavior, which influence the flow in the pipeline.
3. Impurities in crude oil and petroleum gas
Crude oil and petroleum gas can not always be conveyed as pure oil or gas. Oil and gas can be mixed with water and oil can be mixed with gas enclosed in the deposit. This multi-phase mix can cause severe problems in transportation and processing.
You can differ between two- and three-phase mixes. Three-phase mixes are more common in oil production than two-phase mixes.
- 2-phase mixes: Crude oil and petroleum gas, crude oil and water or petroleum gas and water
- 3-phase mixes: Crude oil, petroleum gas and water
4. Changing ambient conditions during conveyance
Enclosed in the deposit with pressures of more than 1000 bar and temperatures of more than 100°C every oil is fluid and pourable. But on the way from the deposit to the surface the pressure and temperature decrease with every foot, which facilitates the formation of different precipitations. Already before reaching the drill hole first inhibitors (chemical agents inhibiting formation of precipitations) have to be added. Crude oil and petroleum gas adapt to the new ambient temperature at latest in the pipeline to the first processing station.
The consequences of oil and gas extraction
The situations described above provide the need for flow assurance each on its own and in their complex combination variations. The problems caused by described situations comprise a variety of precipitation forms like asphaltenes, wax, scale, gas hydrates and other particles in pipelines and processing plants. Furthermore, for example corrosion can occur or the optimal adjustment of pressure and temperature conditions during transport is difficult.
Precipitations decrease the flow rate by narrowing the pipeline diameter and can in worst case plug whole pipeline segments. This precipitations can only be removed with high efforts either physically (heating or shock pressure) or chemically (solvents). The costs and production downtime for these measures are very high.
To prevent or slow down the formation of precipitations inhibitors and additives have to be used to improve the flow properties.
The solution: Developing and testing inhibitors and additives
As the different additives for improving flow properties and additives for influencing general properties interact, thereby changing their effects. Aside from the development of new additives these interactions are an area of research.
Manufacturers of chemicals and service providers in the area of flow assurance have to test their products under as realistic conditions as possible, with reliable and reproducible results. As a wide range of chemicals has to be tested under a variety of ambient conditions and with versatile methods, the measuring instruments have to be specially developed.
Overview of the most common deposits in oil and gas production
Asphaltene
Asphaltenes are poorly soluble components in crude oil that can precipitate when pressure or temperature changes. They are very difficult to remove once they have precipitated. Pressure and temperature conditions in particular influence precipitation (flocculation).
The Flocculation Tester FT5 makes it possible to test inhibitors under reservoir conditions on live oil with changes in the physical conditions corresponding to production or to test the compatibility of different oils.
Wax
Longer-chain hydrocarbons in the oil have a very high solidification point and can adhere to surfaces in a similar way to scale. The wax appearance temperature (WAT) is a limit temperature to be determined below which solid waxes can occur in the oil. Soft waxes are easily sheared off in the flowing medium and form easily removable deposits, harder waxes resist even higher shear rates and are difficult to remove.
The conditions for the occurrence and behavior of the wax layer and the effectiveness of inhibitors can be investigated using a wax flow loop. The simulation of scalable factors such as shear rates, flow velocities and temperature changes is of great importance.
Pour Point
The pour point is the temperature at which a liquid becomes so solid that it can no longer be pumped. This occurs in oils due to the three-dimensional cross-linking of the solidifying higher-molecular components of the crude oil (wax/paraffin). Several different standards are used to check the pour point, each of which has different accuracies and some of which are not suitable for all oil samples.
Pour point depressants (PPD) are used to reduce the solidification temperature by delaying or preventing crystal growth. The highest possible accuracy and repeatability is required from the corresponding measuring devices. The Pour Point Tester can be used to achieve precisely this in a wide temperature range. A finer dosage in the field with corresponding savings and the more targeted development / further development of PPDs is thus possible.
Scale
In oil production technology, the term scale covers all inorganic mineral deposits such as lime or salt deposits. It mostly contains carbonates and sulphates of the alkaline earth metals calcium, strontium and barium.
If scale precipitates during the production of oil or gas and settles on the pipeline walls, in production equipment or already in the formation, this scale reduces the possible production volume. Removing it is usually time-consuming and expensive. Inhibitors are added to inhibit or stop the process in order to prevent deposits. Although “a lot helps a lot” usually applies, this principle is too expensive when it comes to dosing, so that a concentration is desired that prevents scale formation without being overdosed.
These tests can be carried out with a Differential Scale Loop DSL, whereby the concentration can be automatically reduced to failure under variably adjustable conditions. This provides valuable information for both the field engineer and the developer and enables comparisons of different chemicals.
Gas hydrates
When transporting water with crude oil and natural gas, gas hydrates can form under certain pressure and temperature conditions. These ice-like structures trap gas in water molecule cages and can block pipelines or prevent them from restarting.
There are several approaches to prevent this: Thermodynamic inhibitors (THI) prevent hydrate formation, but require high quantities. Kinetic inhibitors (KHI) slow down the formation, while anti-agglomerants (AA) prevent the hydrates from clumping together to form a pumpable mass. KHIs and AAs are referred to as low-dosage hydrate inhibitors (LDHI).
Studies are carried out in pressure chambers (autoclaves) or with rocking cells that simulate turbulent pipeline conditions. A transparent cell such as the Sappire Rocking Cell RCS enables direct observation of the hydrate structure and evaluation of the inhibitors. Interactions between different inhibitors can thus be analyzed.
There are several approaches to prevent this: Thermodynamic inhibitors (THI) prevent hydrate formation, but require high quantities. Kinetic inhibitors (KHI) slow down the formation, while anti-agglomerants (AA) prevent the hydrates from clumping together to form a pumpable mass. KHIs and AAs are referred to as low-dosage hydrate inhibitors (LDHI).
Studies are carried out in pressure chambers (autoclaves) or with rocking cells that simulate turbulent pipeline conditions. A transparent cell such as the Sappire Rocking Cell RCS enables direct observation of the hydrate structure and evaluation of the inhibitors. Interactions between different inhibitors can thus be analyzed.
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