Successful Application of a Differentiated Chelant-Based Hydrofluoric Acid for the Removal of Aluminosilicates, Fines, and Scale in Offshore Reservoirs of the Gulf of Mexico

Abstract

The Ewing Bank 873 (EW 873) Field is an offshore mature field in the Gulf of Mexico that produces hydrocarbon from Pliocene stacked turbidite sands. Wells in the EW 873 Field have experienced production impairment from formation damage, such as aluminosilicates, fines, and scale, including calcium carbonate (CaCO3) and barium sulfate (BaSO4). This paper discusses the results of the successful application of a differentiated chelant-based hydrofluoric (HF) acid to remove formation damage and enhance oil production (by as much as 305%) from Well A-04 in the EW 873 Field. Additionally, the paper presents the chemical analyses of the acid flowback as well as the methods used to characterize the formation damage. More importantly, the paper also focuses on the research efforts that led to the development and successful application of the differentiated chelant-based HF acid. Throughout the research, analytical experiments and corefloods were performed with different acid formulations on cores that contained acid-sensitive clays, CaCO3 and BaSO4. Two formulations contained alpha-hydroxycarboxylic (a-HCA) HF acids, and other formulations contained chelants and chelant HF acids, which were both based on an aminopolycarboxylic acid (APCA). The APCA/HF acid proved to be the most effective formulation, as it achieved the highest permeability increase (relative to brine) and dissolved ions while mitigating precipitation. Furthermore, the APCA/HF acid is biodegradable, and compatibility and corrosion testing indicated that it is compatible with the produced oil samples of Well A-04 and it exhibits low corrosion loss (< 0.05 lbm/ft2) when applied with a chosen corrosion inhibitor on 13-Cr metallurgy, respectively. The development of this differentiated APCA/HF acid highlights the potential of performing successful acid jobs where complex mineralogies, such as CaCO3 and BaSO4, are present.

GLDA/HF Facilitates High Temperature Acidizing and Coiled Tubing Corrosion Inhibition

“…To lower the corrosion rate, a corrosion inhibitor (sulfur-based) was included in the fluid at a concentration of 2 and 4% (Tests 3 and 4), which now has a pH of 2.5 and a concentration of 0.6 M GLDA. The reason for this change in pH and chelant concentration is because this is within the operating condition of the GLDA/HF* or other APCA/HF fluid, based on this work and other publications (Mahmoud et al 2011 andReyes et al 2013b;Sopngwi et al 2014). The corrosion rate, after including the inhibitor, decreased to 0.162 and 0.142 lbm/ft 2 for a 6-hour exposure period at 360°F.…”

Successful Mechanical Removal of Barium Sulfate Tubular Scale by Coiled Tubing: A Gulf of Mexico Case History of an Engineered Approach for Offshore Rigless Interventions

“…1) suggested that the solids contained BaSO 4 scale as the bailedout samples were soluble in concentrated sulfuric acid and insoluble in xylene, warm water, 15% hydrochloric acid (HCl), and also in 10% sodium hydroxide (NaOH). Furthermore, as stated by Sopngwi et al (2014), X-ray diffraction (XRD) analyses of the solids indicated a high presence of BaSO 4 scale as the bailed-out samples contained 90% BaSO 4 . As mentioned earlier, it is important to note that the BaSO 4 tubular scale was concluded to have been caused by incompatible mixing between the barium-rich formation water and sulfate-rich biocide inhibited seawater that broke through from an offset injection well (Table 3).…”

“…Additionally, with NWB formation damage and production impairment already established to be a problem on the well, the intervention created an opportunity to effectively conduct a chelant-based HF acid treatment that increased oil production by as much as 305% on the well (Sopngwi et al 2014). …”

“…However, due to poor injectivity performance and breakthrough of injection water, the water injection was stopped. As mentioned earlier, the well had experienced production impairment from NWB formation damage, and according to Sopngwi et al (2014), the primary sources of the NWB formation damage sources were attributed to aluminosilicates, fines, and BaSO 4 scale. Moreover, the well did not have any history of scale management practices.…”

“…Additionally, the paper presents the tools that were utilized throughout the intervention and the laboratory and field methods that were applied to characterize the BaSO 4 . With NWB formation damage and production impairment already established to be a problem on Well A-04, the successful coiled tubing-conveyed hydroblasting intervention created an opportunity to effectively conduct a chelant-based hydrofluoric (HF) acid treatment that increased oil production by as much as 305% on the well (Sopngwi et al 2014). …”