Significant advances in acidizing chemistry have led to the introduction of sequestering agents, such as hydroxypolycarboxylic acids, followed by chelating agents, to mitigate precipitation reactions. The initiative to obtain fluids with an improved environmental footprint has led to the redesign of treatment fluids to possess distinct advantages, such as stability at higher temperature, broader pH activity, and stronger complex formation. In the area of hydrofluoric (HF) acidizing chemistry, the conceptualization of the unique HF acid reactions on clays and silica surfaces—namely, kinetic controls over the so-called primary, secondary, and tertiary reactions—has facilitated fluid designs that can handle such varied reactions. The work presented here describes the development of a new acidizing fluid containing an environmentally relevant chelating agent and an aminpolyocarboxylic acid. The chelating agent is fully biodegradable, according to the Organization for Economic Co-operation and Development (OECD) protocols, is stable in fluid media from pH 1 to 7 and at high temperatures, and stabilizes the dissolved ions during an acidizing treatment. In HF acidizing, the chelant performance has been tested at 0.6 mol/L and HF acid concentrations from 0.5 to 2%, pH of 2.5 to 4, including a stabilizing agent to mitigate the precipitation of fluorosilicates or fluoroaluminates, and is effective in temperature ranges from 200 to 300°F. Laboratory tests show it to be effective in maintaining in solution dissolved aluminum (3000 to 10 000 mg/L), calcium (5000 mg/L), and iron (6000 mg/L). The use of nuclear magnetic resonance (NMR) spectroscopic analysis revealed additional dissolved-fluoride-containing species that has not been previously reported. Moreover, the chelating agent can also be used when stimulating carbonate rocks in concentrations from 0.2 to 0.6 M with a pH of 1 to 4 and is effective from 125 to 350°F. The representative pore volume breakthrough (PVbt) curves provide an indication of the distinct reactivity of this chelant.
An existing limitation of chelant-based fluids available for sandstone acidizing with hydrofluoric acid (HF) is the presence of sodium in the concentrate of the aminopolycarboxylate fluid, which is common in all chelating agents soluble below pH 3.5. The presence of sodium complicates stabilization of the fluid during acidizing processes because of the myriad of chemical reactions that can impact the outcome of a treatment. The use of chelating agents has expanded the temperature range as well as the type of clay minerals that can be exposed to an HF fluid; however, limitations still exist. Core flow testing at 360°F and corrosion testing from 265 to 360°F were conducted. Flow tests were performed using outcrops of two types of sandstones and inductively coupled plasma (ICP) analysis was conducted to elucidate the ionic composition of the spent fluid. Results reported stem from core flow testing with glutamic acid diacetic acid (GLDA) containing HF at very high temperatures (360°F). To encompass a broad range of mineral composition, two types of sandstone cores were employed-heterogeneous (Bandera, 65% quartz) and clean (Leopard, 95% quartz). Corrosion inhibition of the GLDA/HF fluid for use with coiled tubing (CT) was achieved up to 320°F, employing varying classes of inhibitors. The GLDA/HF fluid exhibited lessened corrosion tendencies and could be inhibited for at least 6 hours at 360°F for drillpipe (mass loss rates of 0.025 to 0.05 in./ft 2 were obtained).The presence of sodium in GLDA/HF could be managed, leading to effective permeability improvement of the Bandera core, while the Leopard core underwent a decrease in overall permeability; this latter observation was attributed to the formation of metal fluorides. Neither the presence of CaCO 3 in the Bandera substrate or the use of KCl brine substituting for the usual NH 4 Cl led to permeability impairment. The overall results indicated that 1% HF and 0.6 M GLDA with an auxiliary agent could circumvent the expected problems associated with HF acidizing and modification, volume minimization, or elimination of preflushes. The use of the GLDA chelant facilitates, when using CT to deliver fluid to hot zones (which can be susceptible to formation damage if aggressive fluids based on HCl or formic acid are used, or if acetic acid is employed), could be jeopardized because of the difficulties inhibiting the corrosive effects of HF, HCl, formic, or acetic blends.
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.
Matrix acidizing is a technique used for stimulating carbonate formations. Fluids used for this purpose are routinely characterized in the laboratory by means of core flood testing. Though several key insights can be obtained using the laboratory core flood technique, simulating exact downhole environments and extrapolation of the results obtained to field-scale has proven challenging. This paper addresses two specific topics related to acid wormholing-upscaling laboratory results to field scenarios and the interaction of reaction products in high pressure reservoirs.To study the upscaling of acid wormholing experiments in field scenarios, a radial core flood testing apparatus was set up to better mimic actual wellbore acidizing flow conditions. The effects of radial flow path and completion type (i.e. openhole versus cased hole) as well as the applicability of the upscaling wormhole propagation model were studied. Furthermore, CT scans of related core samples were performed to characterize wormhole patterns generated by acid dissolution. In addition, tests were performed at high pressures and flow rates to study the effects of the interaction of reaction products on the wormholing process at typical high bottomhole pressure values.Results from radial core flood techniques showed significant differences in terms of pore volume to breakthrough (PVBT) based on well completion type. Further, a current upscaling algorithm for wormhole propagation modeling was verified by comparison to corresponding experimental data, thus demonstrating the suitability of described linear core flow testing methods for fluid characterization and data modeling. The wormhole propagation model (based on the use of fitting coefficient) is well-justified by the probability of increased fluid loss from the wormhole in the case of deeper radial penetration, which overall reduces the efficiency of wormholing. CT scan results revealed nonuniform radial distribution of wormhole propagation, thus shedding light on challenges associated with achieving 360°stimulation around the wellbore. Experiments at higher pressures showed that, at higher flow rates investigated (or beyond optimum) wormhole propagation has a higher than one third dependence on interstitial velocity, signifying that high pressure reservoirs require greater volumes of acid for proper stimulation. Experimental observations are presented to correlate the results obtained thus far and help resolve controversies between various publications.Presented studies highlight the effects of higher pressure in acid wormholing and signify the need for proper volume accounting in terms of job design. A simple radial core flood technique has been developed in this work, and has an advantage in terms of diversion studies by providing a means of arranging high and low permeability core samples in the same order as formation layers and accounting for fluid entrance position.
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.
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