A Simplified Method to Predict and Prevent Asphaltene Deposition in Oilwell Tubings: Field Case

Abstract

Summary The natural state of asphaltenes in petroleum fluids is described as a colloidal system stabilized, to some extent, by the resins that act as peptizing agents. Destabilization of colloidal asphaltenes appears to happen as a result of changes in temperature, pressure, and composition. This can significantly affect the production efficiency of a reservoir during oil recovery. The phenomenon of asphaltene flocculation and deposition in well tubing appears to be influenced by two mechanisms: the fluid-phase (gas/liquid/solid) separation and the well-flow regime. Predictions of the onset of asphaltene flocculation determined by fluid-phase laboratory studies do not necessarily imply that asphaltene deposition will occur during flow conditions. This paper presents a method for predicting the onset of asphaltene deposition under well-flow conditions. This method will allow us to take preventive actions before asphaltenes problems occur by keeping the asphaltenes dispersed in the oil phase. A well-monitoring technique was used in west Kuwait Marrat (Jurassic) deep wells to monitor the well-flow pressure by use of a programmable data logger. The data gathered from the logger predicted the onset of the flow-regime mechanism that influenced asphaltene deposition in well tubing. The deposition thickness of asphaltenes in well tubing was estimated by the data and was found to agree with the results obtained by the caliper test. Introduction It is generally1-6 accepted that crude oil is considered to be a colloidal system comprising fractions of saturates, asphaltenes, resins, and aromatics. Asphaltene fractions are defined as dispersed colloids in the oil phase and are stabilized, to some extent, by the resin molecules that act as protective bodies for asphaltene particles. Colloidal asphaltenes can be naturally or artificially precipitated if the resins' protective shield is removed from asphaltene-particle surfaces. The details of asphaltene characterization have been reported in numerous studies. Asphaltene deposition can occur in different parts of the production system, including in the well tubing, the surface flowlines, and even the nea- wellbore reservoir. Asphaltene precipitation and deposition in oil-production systems depend on the changes in flow conditions, such as pressure, temperature, and oil composition.7–11 The factor that plays a major role in asphaltene problems under flow conditions is well-flow pressure behavior. This pressure controls the well-flow regime within the production system. In tubing, as the well fluid moves vertically, flow-regime changes take place, complicating the multiphase flow, which may cause severe asphaltene flocculation and deposition. This phenomenon can decrease well and, potentially, reservoir productivity, as well as increase production costs by requiring frequent chemical treatments for the removal of asphaltenes. In the Arabian Gulf, it has been observed that asphaltene-deposition problems in well tubing have increased in recent years.12 This may be because of changes in reservoir pressure with time and the increased gas/oil ratio (GOR). The latter has been shown to be an important factor in asphaltene-particle flocculation in production systems. In west Kuwait, asphaltene depositions in well tubings have been increasing in deep wells.12 This paper focuses on the monitoring of asphaltene flocculation and deposition in oilwell tubing. The monitoring technique is based on the interpretation of the flowing-wellhead-pressure data obtained from a programmable data logger.

Effective Removal of Asphaltene Deposition in Metal-Capillary Tubes

“…A few case studies were performed to measure the thickness of the deposited layer in well tubing with diameters of 4.5 and 1.75 in. (Haskett and Tartera 1965;Al-Kafeef et al 2005). In one case, asphaltene deposition in a west Kuwait well was assessed through measurements of flowing wellhead pressure by a pressure gauge, and found to reach one-third of the inner well-tubing radius (Al-Kafeef et al 2005).…”

“…(Haskett and Tartera 1965;Al-Kafeef et al 2005). In one case, asphaltene deposition in a west Kuwait well was assessed through measurements of flowing wellhead pressure by a pressure gauge, and found to reach one-third of the inner well-tubing radius (Al-Kafeef et al 2005). In another case, with a similar method, the deposit in five different wells of the Hassi Messaoud field in Algeria was measured, and found to reach approximately two-thirds of the inner-tubing radius (Haskett and Tartera 1965).…”

“…Costly shutdowns are often required to restore full operation. Furthermore, some wells can become plugged again within 1 to 3 months after chemical treatments are applied (Al-Sahhaf et al 2002). Asphaltene precipitation can be prevented by the addition of large amounts of aromatic solvents or smaller amounts of strong organic acid surfactants.…”

“…In addressing asphaltene precipitation, several different types of dispersants and surfactants were investigated in the literature, most notably strong organic acids such as DBSA and other longchain organic surfactants such as nonyl-phenol (Chang and Fogler 1994a, b;Al-Sahhaf et al 2002). Most studies investigate the effect of dispersants on the onset of asphaltene deposition, measured in terms of the amount of precipitant required to induce asphaltene precipitation (Permsukarome et al 1997;Kaminski et al 2000;Ostlund et al 2004).…”

Colloidal asphaltene deposition in laminar pipe flow: Flow rate and parametric effects

“…A few case studies have been performed to measure the thickness of the deposited layer in pipes with diameters between 2 and 5 inches, and researches found that the deposit thickness reached between 1/3 and 2/3 of the pipe radius. 8,9 Such excessive deposition greatly reduces production efficiency. As a result, better understanding of the deposition process has been sought through modeling efforts.…”