Flow Assurance

Flow AssuranceFlow AssuranceTHE TERM FLOW ASSURANCE is used to evaluate the effects of fluid hydrocarbon solids (i.e., asphaltene, wax, and hydrate) and their potential to disrupt production due to depositionin the flow system.are high molecular weight aromatic organic substances soluble in aromatic solvents (e.g., toluene, diesel) but precipitated by the addition of molecular-weight alkenes (e.g., n-heptane/n-pentane). The molecular weight of asphaltene ranges from 1000 to several hundreds of thousands with a microparticles density of approximately 1.2 gm/cc. Generally , asphaltenes tend to remain in solution or colloidal suspension under reservoir temperature and pressure conditions. Asphaltenes may start to precipitate once the stability of the colloidal suspension is destabilized, which is caused by the changes in temperature or pressure during primary depletion. On the other hand, asphaltenes have been reported to become unstable as a result of fluid blending (comingling) of fluid streams as well as by gas injection during improved oil recovery (IOR) operations. Asphaltene solubility is highly dependent on the composition of the crude, less dependent on the pressure, and hardly dependent on temperature. Asphaltene solubility is higher when the crude is heavier and more aromatic, that is, tends to remain in the crude oil system. A high asphaltene content of crude does not necessarily mean that flowing problems will occur during production; often the contrary is the case5For example, The Venezuelan Boscan crude, which is very heavy, containing 17% of asphaltenes, was produced nearly trouble free. On the other hand, the Algerian Hassi-Messaond crude, which is very light, contains only 0.062% of asphaltenes, met with difficulties during production.

crude oil compositionIt should be noted that the solubility of the heaviest oil fraction, the asphaltenes, depends on a delicate balance between this fraction and the lighter fractions of the crude oil. Any unfavorable disturbance in this balance may induce asphaltene aggregation. For instance, the addition of light, paraffin components to an asphaltene containing crude oil lowers the solubility power with respect to the asphaltenes. As already stated, resin molecules react to the addition of the light paraffin components by desorbing from the asphaltenes in an attempt to reestablish thermodynamic equilibrium, thus increasing the probability of asphaltene self aggregationPressure effectAsphaltenes are also known to aggregate by pressure depletion alone. By decreasing the pressure, the relative volume fraction of the light components within the crude oil increases. This causes an increase in the solubility parameter difference between the crude oil and the asphaltenes, reaching a maximum at the bubble-point pressure. Below the bubble point, asphaltenes are more soluble again due to evaporation of light crude oil components. The relative change in asphaltene solubility has been shown to be highest for light crude oils that are undersaturated with gas and usually contain only a small amount of asphaltenes. This means, somewhat surprisingly, that heavy crudes usually present fewer problems with asphaltene aggregation and precipitation, despite their higher asphaltene content. Of course, heavy crude oils generally possess higher resin amounts, which can explain some of this behavior.Temperature effectTemperature has a less pronounced effect on aggregation than crude oil composition and pressure, but an increase in temperature generally affects the aggregation of asphaltenes by decreasing the solvating power of the crude oil. Some authors state that the asphaltene aggregate size decreases with increasing temperature, while others state that the precipitation of asphaltenes increases with temperature.Preliminary Screening for Hydrocarbon SolidsDe Boer and Leeriooyer (1992) compared the properties of some crude oils in which asphaltene problems were encountered with those that operated trouble free. This comparison is shown in Table 64 for 10 oil systems.Table 64 shows, in addition to observations by De Boer and Leeriooyer, several parameters can be used to identify crudes with the potential to cause flow assurance problems, these are Light crudes high in C1C3 with relatively low C7+ content.High bubble-point pressure, pb.Large difference between reservoir pressure, pr, and bubble-point pressure; that is, under saturation, p = pi pb, is high. High oil-compressibility coefficient, co.Additional literature review suggests: Maximum solids deposit occurs near or at the bubble-point pressure in the piping system. Precipitation occurs during gas lift if gas bubbles are formed. Asphaltene deposit can occur as a result of exposure of oil to a low-pH environment(typically, pH less than 4) during acid treatment of wells. Reservoir wettability reversal occurs after asphaltene deposit. The risk of asphaltene deposit due to gas injectionDe Boer and Leeriooyer proposed a plot that can be used as a first screening tool to identify the potential for the oil to exhibit solid formation problems. The plot, called a De Boer plot, was developed based on laboratory data and numerous field observations. The plot, as shown in Figure 64, defines the following three regions: Region with possible severe solid deposit problems. Region with mild problems. Region with no solid deposit problems.Denoting pi and pb as the initial pressure and bubble-point pressure, respectively, the boundaries of the three regions are defined by the undersaturation pressure difference (pi pb) on the y-axis and the oil density at the initial reservoir pressure on the x-axis.

The colloidal instability index (CII)The colloidal instability index (CII) is another screening criteria, suggested by Yen, Yin, and Asomaning (2001), that can be used to identify crude oil systems with deposit problems. The colloidal instability index is expressed as the ratio of the sum of asphaltenes

Oils with a CII below 0.7 are considered stable while those of above 0.9 are considered very unstable. A graphical presentation of this screening approach is shown in Figure 66 as expressed in terms of (asphaltenes + saturates) content versus (aromatics + resins) content in the hydrocarbon system. This graphical relationship identifies three regions: Unstable. Mild problems. Stable.

stability indexFinally, an asphaltene stability index developed by Oilphase-Schlumberger is shown inFigure 67. The illustration suggests that, if(oi ob) > 0.025, system is unstable(oi ob) < 0.025, system is stable

variety of flow-assurance management strategies may be tailored to address the specific problems expected in the system; they include: Thermal management, such as hot water circulation electrical heating. Pressure management, such as pumping, boosting, blowdown for hydrates. Chemical treatment. Routine or periodic remediation processes, such as pigging, jetting, cutting.