Scale Management in Deep and Ultradeep Water Fields

Abstract

Carbonate and sulfate scales formed on oilfields under natural depletion or water injection support, can occur on a number of critical points from the reservoir to topside facilities impacting on well productivity. Scale control has become a challenging task as oil industry tends to go for deeper water with complex completion wells which may produce from harsh environment conditions (HP, HT). Scale management has become a power tool to assure that oil loss due to precipitation along oil production process be avoided and costs associated to its prevention and remediation treatments be minimized. The most important factor for the success of this approach is that flow assurance strategies are considered in the field planning. Scaling risk analysis should be carried out, assessing scale tendency and intervention difficulties associated with the well design and field features. These issues are addressed in the exploration phase of the field, determining, based on risk analysis and economic evaluation criteria, the appropriate technology to be adopted. In the production phase, production data, down hole pressure measurements as well as chemical monitoring of produced water are essential for diagnosing whether any scale is being formed and to review the decisions made if necessary. In order to demonstrate the suitability of this approach, cases regarding a siliciclastic turbidite and a carbonate reservoirs in the deepwater and ultra-deepwater fields will be discussed showing different scale management strategies, such as, scale modeling by thermodynamic calculations, scale control by using downhole scale inhibitor injection, scale inhibitor squeeze treatment, scale dissolver treatment, sulfate removal unity, and downhole surveillance instrumentation (PDG, TPT).

Rock fluid interactions during seawater injection in carbonates: An experimental evaluation on dolomitization and anhydrite precipitation

“…Exploitation projects in Brazilian carbonates consider the injection of sulphate-free seawater (designated desulphated seawater) as a secondary recovery method. This premise is tied to the lessons learned from siliciclastic reservoirs (Bezerra et al, 2013). Desulfation processes are designed to minimize problems associated with scaling (Arai et al, 2010).…”

Evaluating the Effectiveness of Red Onion Skin Extract Derivatives as Oilfield Scale Inhibitors

“…Scale inhibition can occur when one or more aspects of the crystallization process is disrupted [2,3]. Sulfate and carbonate scales have been identified as the most common inorganic scales found in oilfields worldwide [4][5][6] While Sulfate scales, which include calcium sulfate (CaSO 4 ), barium sulfate (BaSO 4 ) and strontium sulfate (SrSO 4 ) are formed due to the mixing of incompatible brines, specifically formation brine and injected seawater, carbonate scales are deposited due to change in operating conditions, such as drop in pressure in production wells [4,5,7,8]. Mineral scale formation can be described with the following reactions [3].…”

Fluid flow effects on CO2 corrosion: a review of applications of rotating cage methodology

“…More recently, the corrosion associated with CO 2 gas has become a problem because of the production of high pressure deeper wells with high CO 2 concentrations and temperatures (Heiderbach, 2011). In Brazilian pre-salt production, the CO 2 concentration in the associated gas may go beyond 20 per cent in some areas (Cezar et al , 2015), and when it is dissolved in an aqueous medium with a high salt concentration (Bezerra et al , 2013), there are challenges in selecting the metallic materials to use and obtaining the desired performance (Beltrão et al , 2009). Additionally, calcium contents on the order of 10,000 ppm in the produced water (Bezerra et al , 2013) as well as corrosion issues can lead to flow assurance problems because of CaCO 3 scaling formation, in addition to iron carbonate (FeCO 3 ).…”

“…In Brazilian pre-salt production, the CO 2 concentration in the associated gas may go beyond 20 per cent in some areas (Cezar et al , 2015), and when it is dissolved in an aqueous medium with a high salt concentration (Bezerra et al , 2013), there are challenges in selecting the metallic materials to use and obtaining the desired performance (Beltrão et al , 2009). Additionally, calcium contents on the order of 10,000 ppm in the produced water (Bezerra et al , 2013) as well as corrosion issues can lead to flow assurance problems because of CaCO 3 scaling formation, in addition to iron carbonate (FeCO 3 ). On the other hand, Barker et al (2018a) highlight that high divalent cations concentrations can promote the formation of different, competing scales in preference to FeCO 3 , affecting the corrosion of steel.…”