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ABSTRACT The relative tendency of pipeline girth weld coatings to shield cathodic protection (CP) current was studied in the laboratory. Four types of liquid coatings: epoxy, epoxypolyurethane, polyurethane, and wax were investigated, with fusion bond epoxy (FBE) and a polyethylene shrink sleeve used for comparison. The results showed that the liquid coatings, when applied extra thin to accelerate the kinetics of absorption and current transmission, all disbonded by blistering, and all allowed CP current to be transmitted. For all coatings, micro-defects were found to be associated with the blisters, and it is believed that these defects were necessary to allow effective CP under disbonded coatings. INTRODUCTION Girth weld coatings based on polyethylene or PVC sheeting such as shrink sleeves and tape wraps can fail in such a way that cathodic protection cannot protect disbanded areas. Water from the soil can migrate underneath these coatings, either at the bond with the mainline coating or at any point along the intra-coating tape lap. Problems are exacerbated due to tenting of the coating over the weld bead. These systems are commonly used with 2-layer and 3-layer coating systems due to their chemical similarity. They are often not specified for fusion bond epoxy (FBE) coatings, coal tar enamels, and liquid pipeline coatings, for which liquid epoxies and polyurethanes are preferred. Pipeline coatings are designed to be good insulators with high dielectric strength so that current should not be able to readily pass directly through the coatings in the absence of a holiday. However, FBE pipeline coatings are known to fail in such a way that allows cathodic protection to protect the steel underneath disbonded FBE coating, even in the absence of a holiday. It is believed that the high permeability of FBE coating to water is the reason for the apparently transparent nature of FBE coating to cathodic protection currents. Pipeline coatings based on polyurethane are known to have a higher affinity for water uptake, while liquid epoxy coatings are formulated to resist water absorption to a great extent. When a coating absorbs groundwater, the ionic permeability of the coating, as measured by electrochemical impedance spectroscopy, will increase by several orders of magnitude. In the absence of a holiday, the CP current passing directly through the coating will be very low, but the corrosion rate will also be low. In the case where the coating disbonds at a holiday and a crevice forms, cathodic protection permeates up the crevice to a certain extent, and is dependent on a number of variables. For the present study, it is the permeation through the coating which is at issue. BACKGROUND Liquid epoxies and polyurethanes are commonly used as girth weld coatings due to improved adhesion and perceived reliability with these systems as compared with shrink sleeves and polyethylene tapes, which can shield cathodic protection when they disbond. For girth weld areas, liquid coatings are generally used in conjunction with fusion bond epoxy (FBE) mainline coatings. More significantly, liquid coatings are used in the repair and rehabilitation of existing pipelines. Cathodic protection (CP) shielding occurs when a properly functioning cathodic protection system does not protect an area on a pipeline at which the steel is exposed to a corrosive environment. For the purposes of this paper, CP shielding may be defined as a location at which coating disbondment occurs in the absence of a local holiday, resulting in a scenario for which the CP system cannot protect the disbanded region. Previous investigations have addressed various issues regarding cathodic protection shielding
ABSTRACT The general objective of this laboratory evaluation was to provide an assessment of the current corrosive conditions of Khafji and Hout Fields been exploited by Khafji Joint Operations (KJO). Rotating Cylinder Electrode in an Autoclave (RCA) and in an electrochemical set-up (RCE) were used to determine the baseline corrosivity at selected production conditions using the weight loss and linear polarization techniques respectively. Also, Electrochemical Impedance Spectroscopy (EIS) was used to determine the oil/water inversion point. Finally the measured corrosion rates where compared with the prediction of two models. It was found that the corrosion rates for the Khafji Field condition ranged from 0.3 mm/yr (11.9 mpy) to 0.31 mm/yr (12.3 mpy), while the corrosion rate for the Hout Field condition ranged from 0.7 mm/yr (27.8 mpy) to 0.72 mm/yr (28.6 mpy). The water-cut inversion point for the Khafji Field condition was 75%, while the critical water-cut inversion point for the Hout Field condition was 70%. The predicted corrosion rates showed to be in good agreement with the corrosion rates measured in laboratory tests for the conditions of Khafji Field but overestimated the corrosion rates measured in the sour environment. It is believed that the lack of sufficient corrosion rate data in dynamic conditions at high concentrations of H2S contributed with the non-accurate prediction at the conditions of Hout Field. It was recommended to keep critical production and transmission lines continuously monitored and to implement inspection programs to determine the actual condition of the Hout Field production facilities. INTRODUCTION The Khafji Joint Operations (KJO) occupies the neutral zone between Saudi Arabia and Kuwait at the town of Khafji, Saudi Arabia. KJO currently operates two fields: Khafji Field and Hout field. The Khafji field produces from at least four sweet producing horizons. The Hout field produces a sour limestone. The production target of Khafji Crude Oil (American Petroleum Industry, API, gravity of 28.5) is 300,000 barrels per day (bpd) and the production target of Hout Crude Oil (API 32.8) is 50,000 bpd. Crude oil production from the sweet horizons comes through wells on numerous well jackets and is sent by flow lines to flow stations. These are single platforms receiving flowlines from the individual well structures containing inlet manifolds to combine the production from the well jackets. The flow stations contain production separators, test separators, chemical injection equipment and booster pumps to send the production to the Gathering Station (GS). Gas and oil are separated at the flow stations. All the production from sour wells flows to a separated GS. Water is not separated off-shore. From the GS the produced oil and water is sent to shore through 24 or 26 inch transmission lines which are approximately 40,000 meters long. The oil produced from wells is normally accompanied by produced water, natural gas and corrosive gases, such as carbon dioxide and hydrogen sulfide. In the absence of water to create a water-wet surface, crude oil at a typical production temperature is not, by itself, corrosive. Even a thin film of water on the metal surface is sufficient to create corrosion problems, because the corrosive gases dissolved into the water phase produce corrosive environments. As oil and gases are removed from the well, the pressure of reservoir slowly drops. To maintain the pressure, water flooding is often used, injecting into the reservoir either produced water or seawater. As the reservoir ages, water is produced along with the oil, and the percentage of water in the produced fluid increases. The corrosivity of produced fluids is infl
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Khafji Field (0.94)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Hout Field (0.94)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Khafji Field (0.94)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Hout Field (0.94)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)