What’s new in production

Two 1943 oil pipelines from Texas to the East Coast helped win World War II. “Big Inch” carried oil from East Texas oil fields, and “Little Big Inch” carried gasoline, heating oil, diesel oil, and kerosene. “Without the prodigious delivery of oil from the U.S., this global war could never have been won,” says historian Keith Miller.

To emphasize the critical importance of flow assurance, Miller’s comment would be hard to top. An interesting paper, “Flow Assurance Engineering in Deepwater Offshore–Past, Present, and Future” (Bomba, et.al., 2018), surveys the challenges. Let’s look at one clever method devised to deal with asphaltenes, among the most difficult of these challenges.

As the authors point out, asphaltenes have been a production issue from the earliest days of the industry, but they only became a significant issue in deepwater exploration during late 1996. Defined as the fraction that precipitates upon the addition of an excess of n-alkane, the diversity of asphaltene production issues arises from the variety of oil types, their maturation and charge history, the chosen production schemes, and physical conditions. These variables produce an enormous number of permutations under which asphaltenes can be an issue.

Driving factors. Pressure, composition and temperature are the driving factors for asphaltene precipitation and deposition. Among them, pressure and composition have the most significant impact. Precipitation and deposition increase in severity, with pressure decreasing until reaching the bubble point, whereupon the asphaltene solids tend to re-dissolve.

However, this re-dissolution can be slow and incomplete. The two main driving forces—pressure and composition—of precipitation and deposition are superficially similar, but result in different precipitated fractions, and with different behaviors. Observations indicate that the composition-driven precipitation has a higher tendency to form deposits than the pressure-driven precipitation; the mechanisms of this are yet to be investigated.

The complex nature of asphaltene, and unpredictability of deposit formation, have made management of asphaltene risk in wells a challenging task. Asphaltene deposition tends to occur above the bubble point, concentrating this flow assurance hazard to the wellbore and near-wellbore formation, and occasionally to the wellhead or upstream flowline. These locations are more difficult to monitor and access than those topside, while associated remediation costs are at least an order of magnitude higher.

Below the bubble point, the precipitated agglomerates may settle in low velocity or dead-space volumes, such as separators, reducing their efficiency; they may contribute to the stabilization of foams and emulsions, increasing liquid carry-over and separation times; or they may contribute to other deposits, forming wax-asphaltene or scale-asphaltene composites, which impair system components. These phenomena, while costly, tend to occur in relatively accessible areas, with both upstream and downstream access or injection possibilities.

Hashmi and Gnosh (2014) observe that asphaltenes in petroleum flow streams are often compared with low-density lipoproteins in [the] blood stream, both being responsible for flow restriction, pressure surge, and finally complete blockage, resulting in system shutdown, owing to phase separation and deposition on the flowlines.

Residual surface charge. According to the authors, “Asphaltene–resin moieties in crude oil are found to carry residual surface electric charge, which is characteristic to their colloidal structure, asphaltene–resin ratio, and system pH. This research investigated the possibilities of controlling asphaltene deposition in oil wells by applying static electrical potential, taking advantage of their residual surface charge.

Laboratory experiments were conducted at static and also in dynamic conditions, constructing a dual-flow loop setup, equipped with precision pumping, pressure recording, and regulated DC power supply. Neat and heptane-diluted crude oil having inherent asphaltene deposition tendencies is used to investigate the influence of DC electrical potential on asphaltene deposition tendencies. Real-time deposition trend is interpreted through differential pressure build-up across the flow loops and also through quantitative estimation of deposited mass.

“The results were encouraging, showing up to 180% reduction in asphaltene deposition in the cathode loop and about 140% increase on the anode loop at an [optimized] potential of 60V DC. Further, it was observed that the higher the n-heptane dilution, higher is the effect of static potential in terms of arresting deposition. Based on these optimistic results, further studies and upscaling are planned, and looking at the possibilities of controlling asphaltene deposition, by converting the well into a cathode, along with a nearby sacrificing anode well, applying optimum electrical potential.”

Conclusions. Based on the results of the experimental works described in their study, the authors conclude: 1) The asphaltene–resin colloids in the crude oil have excess negative charge, which is the cause of asphaltene deposition while in dynamic state; 2) Application of DC potential resulted in rapid, excess asphaltene deposition on anode surface, while little or no deposition occurred on cathode surface; and 3) The amount of n-heptane used to dilute the crude oil determines the surface charge of asphaltene–resin colloids, which affects the deposition rate and quantity. The higher the dilution, higher is the effect of DC potential for deposition rate and quantity.

As with many solutions, the perfect is the enemy of the good. Given the industry’s record of achievement, this solution, while good, is likely not the last word. WO