Field results and laboratory data are presented for the purpose of identifying best practices for two different acidizing fluids based on chelating agents containing hydrofluoric (HF) acid employed in clean-up treatments in high-rate water pack completions (HRWP). The HF fluids are a newly introduced aminopolycarboxylic acid (APCA), pH 2.5 to 3 that contains sodium ions, and an established hydroxycarboxylic acid (HCA) fluid, pH 3, sodium-free. Flow testing was conducted at the anticipated bottomhole static temperature (BHST) of 270°F in synthetic packed columns with formation sand. However, the field conditions at which the treatments were run corresponded to a BHST of 202 to 216°F and a bottomhole pressure (BHP) of 1,800 to 2,000 psi. The permeability of the sands was 89 to 162 md. Comparative data and results stemming from laboratory testing and field use of the HF/chelant fluids are analyzed for concentrations of 1 and 1.4% HF and APCA at 0.6 M, and 1% HF with HCA. Field data and production results are discussed for two set of wells treated with each type of HF fluid. The chemical differences, reactivity and characteristics among the APCA/ and HCA/ -HF fluids on formation sand and on formation core are described. Fluid testing excluded acid preflush and NaCl or KCl was the sole brine employed. Laboratory results indicate that both HF fluids are compatible with the brines used within the scale of the experiment and provide full or increased relative permeability. The field application of the APCA/HF fluid in HRWP appears to perform less efficiently, requiring longer pumping times, than the HCA/HF fluid. A salient observation from laboratory testing indicates greater effectiveness at pH 2.5 vs. 3 for the APCA/HF fluid. A differentiating characteristic is that the APCA/HF fluid can be used to treat heterogeneous sandstone with moderate carbonate content and HCA/HF is mostly compatible with clean sandstone unless an acid preflush is incorporated. The operational outcomes observed during the field use of the APCA/HF fluid appear to indicate significant differences in laboratory vs. field performance requiring further assessment to identify appropriate practices in HRWP. The APCA/HF fluid can stabilize problematic ions in the spent fluid without the need for acid preflushes and without maintaining highly acidic conditions. The effective field use of the newly developed APCA/HF fluid containing Na+ with and without an acid preflush indicates that future work with this type of stimulation fluid is viable in matrix acidizing.

Because of increased activity in deepwater and high-pressure/high-temperature (HP/HT) environments, the safe operation of corrosion resistant alloys (CRAs) of different types is important. Reservoirs can be subjected to different flow impairment mechanisms that can require the use of acidizing fluids. Titanium (Ti) alloys can be present in subsea completions and in the casing of geothermal wells, as these are able to withstand ultrahigh-pressure and temperature and corrosive conditions. The need to remove clays or silica fines obstructing fluid flow in deepwater wells and enhanced geothermal systems can pose difficulties to operators if the use of hydrofluoric (HF) acid fluids is necessary. At present, there is no HF-acid fluid compatible with Ti alloys because any contact of HF acid with a Ti alloy will result in its corrosion and dissolution. In this paper, the development of a corrosion inhibitor solution to protect Ti alloys against HF-acid attack is presented.Different metallurgical specimens (Ti, chrome, carbon (low or high) steel) were exposed to an HF-acid fluid based on a sodium-containing aminopolycarboxylic acid (APCA-Na) chelating agent. The Ti specimens (Grade-1 and -29) underwent delamination or blistering at low temperature (140 -250°F), depending on the inhibitor and type of alloy present. An HF acid modulating agent was used to help minimize corrosion and the dissolution of Ti. The steel alloys were tested at 260°F with the HF-acid/ APCA-Na fluid, displaying minimal mass loss resulting from corrosion. The main effect observed was surface pitting. While suitable inhibitors exist against HF acid for CRA tubing, there are still limitations, such as in mixtures containing acetic acid, which lead to pitting, complicating the inhibitory process. Temperatures in excess of 100°C limit the exposure time to an HFacid fluid, further convoluting the corrosion protection and inhibitor optimization for multiple alloys. Use of the described HF-acid fluid containing APCA-Na in conjunction with the set of HF acid anti-corrosion agents can facilitate acidizing in wells whose completions contain HF-acid-sensitive alloys, including Ti.

Using hydrofluoric (HF) acid for the removal of clays and silica minerals impairing permeability in sandstone formations requires fluids free of sodium or potassium ions. High temperatures (> 300°F) further limit HF acid use and its effectiveness because of potentially damaging effects to the formation and its corrosivity. This paper discusses laboratory testing of an aminopolycarboxylic acid (APCA) fluid containing 1 to 1.5% HF acid and highlights its advantages and differentiating characteristics with respect to previous HF acid fluids. Core flow testing at 360°F was conducted on outcrops of two types of sandstone representing a heterogeneous (65% quartz and illite/kaolinite with feldspars) and a clean (95% quartz) type of mineralogy. The APCA fluid containing HF acid, which incorporates a modulating agent for the HF acid-secondary reaction on aluminosilicate minerals, was compared to the pure APCA (pH 2) fluid and formic acid. Effluent analysis of the spent fluid was completed by inductively coupled plasma (ICP) optical emission spectroscopy (OES). Corrosion inhibition testing was completed for coiled tubing (CT) and carbon steel (NT-95) up to 360°F, employing various classes of inhibitors. Using an APCA chelating agent in sandstone HF acidizing expands the temperature range of application and the type of minerals that can be exposed to such fluid. High-temperature HF acidizing is also delimited by the type of steel tubing that can be exposed to such fluid, placing significant demands on corrosion control. Laboratory results obtained in this investigation demonstrate that corrosion can be well managed for a fluid having a pH of 2.5 and HF acid concentrations of 1 to 2% from 250 to 275°F and at 300°F with a pH of 4. Testing results show that the APCA/HF fluid, having a pH of 2.5, can effectively be used to treat heterogeneous sandstone of moderate carbonate content at 360°F and is also compatible with a clean sandstone. The APCA/HF fluid stabilizes the most problematic ions in the spent fluid—Al3+, Fe2+/3+, Ca2+, and alumino-fluorides—without the need for acid preflushes and without maintaining highly acidic conditions. Comparison to formic acid and HF acid-free APCA fluid is presented. Using aminopolycarboxylic acid-type chelants is restricted by the materials commercially available, all of which contain sodium, with one exception, which has ammonium. Hence, HF acidizing has been restricted to ammonium-containing fluids. A differentiating characteristic of the fluid reported here is its ability to sustain Na+ concentrations exceeding 1 M and K+ concentrations in excess of 0.5 M. Furthermore, it is suitable for the treatment of carbonate-laden mineralogy formations up to 360°F.