Flow assurance is required to determine the optimum flowline pipe size based on reservoir well fluid test results for the required flowrate and pressure. As the pipe size increases, the arrival pressure and temperature decrease. Then, the fluid may not reach the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the pipe size is too small, the arrival pressure and temperature may be too high and resultantly a thick wall pipe may be required and a large thermal expansion is expected.

It is important to determine the optimum pipe size to avoid erosional velocity and hydrate/ wax/asphaltene deposition. Based on the hydrate/wax/asphaltene appearance temperature, the required OHTC is determined to choose a desired insulation system (type, material, and thickness.) If the flowline is to transport a sour fluid containing H2S, CO2, etc., the line should be chemically treated or a special corrosion resistant alloy (CRA) pipe material should be used. Alternatively, a corrosion allowance can be added to the required pipe wall thickness. capital expense (Capex) and operational expense (opex) using CRA, chemical injection, corrosion allowance, or combination of the above should be exercised to determine the pipe material and wall thickness.

The picture above illustrates one example of how to select pipe size from flow assurance results. The blue solid line represents inlet pressure at wellhead and the red dotted line represents outlet fluid temperature. The 8” ID pipe may require a heavy (thick) wall and the 12” ID pipe may require a thick insulation coating depending on hydrate (wax or asphaltene) formation temperature.

One of the most critical steps in identifying and quantifying flow assurance risks is fluid sampling. Fluid samples can be obtained from downhole and/or from surface separator. It is a good practice to collect at least two downhole samples with one serving as a back-up and collect at least three one-gallon samples from the separator. A certain amount of stock tank oil samples are needed for other crude oil analyses (geochemical and crude assay).

Once the fluid samples are in the lab, numerous tests will be performed to measure the fluid properties. Compositional analysis of the downhole sample would be performed through at least C36þ, including density and molecular weight of the Heptanes plus. Pressure-Volume Relations are determined at reservoir temperature by constant mass expansion. This measurement provides oil compressibility, saturation pressure, single phase oil density, and phase volumes. The compositions and gas formation volume factors for the equilibrium reservoir gas during primary depletion can be obtained by performing differential vaporization at reservoir temperature. Gas viscosities are then calculated from the composition. Undersaturated and depleted oil viscosity at reservoir temperature can be measured by using capillary tube viscometry.

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Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.