Hot Oil and Gas Wells Can Be Stimulated Without Acids
- Wayne Frenier (Schlumberger) | Mark Brady (Schlumberger) | Salah Al-Harthy (Schlumberger) | Roberto Arangath (Schlumberger) | Keng Seng Chan (Schlumberger) | Nicolas Flamant (Schlumberger) | Mathew Samuel (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- November 2004
- Document Type
- Journal Paper
- 189 - 199
- 2004. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 5.5 Reservoir Simulation, 4.1.2 Separation and Treating, 1.8 Formation Damage, 3 Production and Well Operations, 1.6 Drilling Operations, 5.6.4 Drillstem/Well Testing, 4.3.1 Hydrates, 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale, 2.2.2 Perforating, 2 Well Completion, 5.4.10 Microbial Methods, 4.2.3 Materials and Corrosion, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1 Reservoir Characterisation, 4.1.5 Processing Equipment, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 3.2.4 Acidising, 3.1.6 Gas Lift, 5.5.8 History Matching, 1.2.3 Rock properties, 1.10 Drilling Equipment
- 1 in the last 30 days
- 2,032 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
A revolutionary family of treating fluids designed for the stimulation of critical, hot, or exotic oil and gas wells has been developed through application of detailed chemical and engineering studies.1-3 Formulations based on the hydroxethylaminocarboxylic acid (HACA) family of chelating agents have now been used to successfully increase production of oil and gas from wells in a variety of different formations. Included in the field test matrixes were new and producing wells drilled into carbonates and sandstone formations. The temperatures of the wells treated ranged from 230 to 370°F (110 to 187°C) bottomhole static temperature (BHST).
Because these formulations do not contain high concentrations of corrosive mineral or organic acids (the formulations are less acidic than carbonated beverages), very low corrosion rates of the tubulars can be achieved by application of small amounts of special, inexpensive corrosion inhibitors. The mild fluids also are highly retarded so that high-temperature carbonates can be stimulated and sensitive sandstone formations are not damaged. The fluids have reduced health, safety, and environmental (HSE) footprints because:
(1) They are much less toxic to mammals as well as to aquatic organisms than mineral acids or organic acids such as hydrochloric (HCl), hydrofluoric (HF), or formic acid.
(2) The fluids are returned to the surface at pH values between 5 and 7, and they frequently can be added to normal well production fluids without neutralization.
(3) Because of much lower corrosion rates for corrosion resistant alloys (CRAs), lowered concentrations of Ni and Cr will be in the well returns compared with conventional acids that also may contain antimony (as a corrosion inhibitor).
While mineral acids can be very effective stimulation fluids at low temperatures, the use of HCl-based fluids at high temperatures [generally defined as greater than 200°F (93°C)] can cause many problems. The major concerns are damage to corrosion-resistant tubular materials, toxicity of the fluids and inhibitors, too rapid attack on the formation (carbonates), and massive damage to clays in sandstone formations. Alternative fluids based on the HACA family of chelating agents can be formulated to alleviate these problems.
This paper will describe the scientific basis for using these fluids in hot formations. We also describe a completely new family of matrix stimulation fluids, based on HACA chemicals, that has a unique ability to be tailored to specific formation conditions. Because of the high acid solubility of HACA chemicals, formulations of low- as well as high-pH fluids have been produced. A major application will be that of stimulating high-temperature carbonate formations where mineral acids cannot be pumped fast enough to produce wormholes unless these are retarded by the formation of emulsions. In addition, this paper describes results from laboratory tests and field treatments using chelating agent fluids for matrix stimulation of high-temperature sandstone formations. Laboratory experiments have been conducted up to 400°F (204°C) and have included rotating disk tests using carbonate specimens to determine the kinetics and coreflood tests using carbonate and sandstone cores to validate dissolution mechanisms and to qualify formulations for use in field applications. Results from field applications up to 370°F (187°C) are presented.
Literature on Use of Chelating Agents in Well Stimulation.
Chelating agents are materials used to control undesirable reactions of metal ions. In oilfield chemical treatments, chelating agents1 are frequently added to stimulation acids to prevent precipitation of solids as the acid spends on the formation being treated. See references by Frenier2 and Frenier et al.3 for more detailed reviews. The materials, which were evaluated, include HACA such as hydroxyethylethylenediaminetriacetic acid (HEDTA) and hydroxyethyliminodiacetic acid (HEIDA), as well as other types of chelating agents.
Fredd and Fogler4-6 have proposed uses for ethylenediaminetetraacetic acid (EDTA)-type chelating agents. This application uses the chelating agents as the primary dissolution agent in matrix acidizing of carbonate formations [calcite, which is calcium (CaCO3) carbonate, and dolomite, which is calcium/magnesium carbonate(Ca/MgCO3)]. Because HCl reacts so rapidly on most carbonate surfaces, diverting agents, ball sealers, and foams7 are used to direct some of the acid flow away from large channels that may form initially and take all the subsequent acid volume. By adjusting the flow rate and pH of the fluid, it may be possible to tailor the slower-reacting chelate solutions to the well conditions and achieve maximum wormhole formation with a minimum amount of solvent.
Disodium EDTA has been used as a scale-removal agent in the Prudhoe Bay field of Alaska.8,9 In these applications, CaCO3 scale had precipitated in the perforation tunnels and in the near-wellbore region of a sandstone formation. Huang et al.10 described organic acid formulations for removal of scale and fines at high temperatures.
One aspect of chelating agent fluids has proven to be most useful for treating a wide range of formations and damage mechanisms. This is the large range of different types of formulations that can be produced by changing the pH with addition of acids or bases. The most common commercial fluids available are tetrasodium EDTA and trisodium HEDTA; these have pH values of approximately 12. Table 1 shows the pKa values for the carboxylate groups in these molecules. These values also define the buffer points because the buffer power is at a maximum when pH=pKa. Many different formulations (usually proprietary) can be produced by addition of mineral acids or organic acids to sodium EDTA or sodium HEDTA to make acidic fluids that are quite aggressive for dissolving calcite. Based on the pK values, HEDTA would buffer strongly at pH 2.6 and 5.4 (measured at 25°C), while EDTA could buffer at pH 2.0, 2.7, and 6.1. However, only HEDTA fluids can actually be produced as formulation with pH values <5.0 because of the much higher solubility of HEDTA acid compared with EDTA acid.
The experimental program included tests to determine the kinetic parameters for dissolution of calcite using the rotating disk methods and for determining the extent of wormhole formation using coreflood tests.
|File Size||3 MB||Number of Pages||11|