Slug Flow Characteristics and Their Effect on Corrosion Rates in Horizontal Oil and Gas Pipelines

Abstract

SPE Members Abstract The flow characteristics of slug flow and their effect on the corrosion rates are examined experimentally in a 100 mm diameter, horizontal, Plexiglass pipeline. The system was maintained at a pressure of 2 bars and temperature of approximately 35C. After initial tests with oil only and water only, 80% water and 20% oil, and 60% water and 40% oil mixtures were examined. Carbon dioxide was used as the gas. Using the stationary slugs described by Jepson, the mean wall shear stress and turbulent intensity at 7 different axial and three circumferential locations were measured using flush mounted TSI hot film anemometer probes. The regions included the film region ahead of the slug, the mixing zone at the slug front, and a short distance into the slug body. The oil, water, and carbon dioxide fractions were measured across a vertical diameter using a sampling probe. Corrosion rates at the top and bottom of the pipe were measured using electrical resistance probes. Pressure gradients across the slug front were also taken. The results clearly show that the slug front is a highly turbulent region that has large wall shear stresses at the bottom of the pipe. The wall shear stress decreases with circumferential position but increases with increasing oil fraction in the fluids. For a Froude number of 12, the shear stress for water only is 26 N/m. For the mixture of 60% water and 40% oil a value of 97 N/m is attained. These are much greater than anticipated. Instantaneous values are much larger than this. The corrosion rates are much greater than those predicted by usual laboratory methods, such as rotating cylinders or disks. The rates are shown to be greatest at the bottom of the pipe and correspond to the regions of high wall shear. Corrosion rates increase with an increase in oil concentration at the same Froude number. It is concluded that the wall shear stress associated with the slug front is sufficient to continuously remove corrosion products from the pipe wall. Introduction Internal corrosion of carbon-steel pipelines is a common problem in oil and gas production facilities which are designed for long-time operation. This problem has triggered the consideration of many corrosion control programs in various oil fields around the world. These methods include the selection of a pipe-wall thickness with sufficient corrosion allowance, the use of corrosion-resistant-alloy materials, the use of internally-coated pipe, dehydration of the oil-water mixture, and the corrosion-inhibitor injection. New pipeline design and service must consider corrosion control. Surface treatment such as injection of corrosion inhibitor into the flow system of pipelines is widely adopted. However, inability to predict accurately the flow regime in the multi-phase flow that would occur in the pipeline could seriously change the effectiveness of the inhibition process. By continuous injection or batch treatment commercial corrosion inhibitors can adsorb to the metal surface and form a barrier in the form of a protective film. This film can prevent further corrosion. One of the crucial parameters in selecting an inhibitor is to know its effectiveness in service environments. A knowledge of the metal surface condition, operating temperature and pressure, fluid properties, solution pH and chemistry, and flow conditions, such as flow velocity and single- or multi-phase flows is necessary. Dissolved gas, especially oxygen and carbon dioxide, and fluid dynamics can drastically reduce the effectiveness of inhibitors. The corrosion processes in oil and gas production pipe- lines involve the interaction between metal wall and the flowing fluids. Relative motion between the fluid and the metal surface win in general affect the rate of the corrosion. Ellison and Wen have proposed a rational classification for flow effects on corrosion. P. 215^