Summary 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: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.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.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). Introduction 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. Experimental Procedures 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.

Effective mud removal is a prerequisite to attain the cement coverage necessary for good zonal isolation. Because of this, the oilfield industry has dedicated considerable attention to the topic of mud displacement over the past 60 years. The first 2D annular displacement simulator was introduced in the 1990s and it is now widely available. The results are satisfactory for simpler configurations. However, for deeper wells with complex trajectories such as highly deviated or horizontal wells, the models start to show their limits. This paper discusses the advancements in mud displacement simulation that overcome the limitations of the previous generation simulator and provide a more realistic simulation in highly deviated and horizontal wells. A new generation simulator now provides high-fidelity results via a combination of: 1) a pipe displacement model, accounting for fluid contamination inside the pipe; 2) a high-resolution annular displacement model, accounting for the complex 3D annulus shape with full determination of axial and azimuthal flows; and 3) a stiff-string centralization model based on the finite-element method, predicting casing position in a 3D wellbore. A primary cementing operation for a horizontal well was studied and an unprecedented congruence was witnessed between predicted fluids annular concentration maps and ultrasonic cement log. The simulator was also able to predict complex channeling patterns in the annulus. These results allow a better understanding of the cement placement technique and provide means to optimize the sequence of fluids to achieve effective mud displacement in the well. Enabled by advancements in today’s computing capabilities, the new simulator is able to simulate both simple and highly complex scenarios more realistically. Finally, the new model allows better planning and decision making to achieve zonal isolation and well objectives.

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 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°F to 370°F (110–187°C) bottom hole 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 high-temperature carbonates can be stimulated and sensitive sandstone formations are not damaged. The fluids have reduced health, safety, and environmental (HSE) footprints because:they are much less toxic to mammals as well as to aquatic organisms than mineral acids or organic acids such as HCl, HF or formic acid;the fluids are returned to the surface at pH values between 5 and 7 and frequently can be added to normal well production fluids without neutralization;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). Introduction While mineral acids can be very effective stimulation fluids at low temperatures, the use of HCl-based fluids at high temperatures (generally defined as above 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 hydroxethylaminocarboxylic acid (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 describe a completely new family of matrix stimulation fluids based on HACA chemicals, which 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 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 core flood 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.

Summary Good casing centralization during cementing operations is a key factor for achieving proper mud displacement and obtaining hydraulic isolation in the annulus. To this end, centralizers are often placed along the casing to position it centrally in the borehole. The optimal number of centralizers and their spacing are determined with simulation software. Until now, the industry has typically used calculation methods derived from American Petroleum Institute (API) Spec. 10D (2002, 2004) to predict casing eccentricity in the wellbore. The calculations are based on an analytical soft-string method, which models an element of casing string between two centralizers as a bifixed-ends beam. However, in drilling operations, the use of a numerical stiff-string method to compute torque-and-drag forces is now becoming widespread. It accounts for tubular bending stiffness and provides a more realistic analysis of the stresses and loads acting upon the drillstring and the borehole. The stiff-string technique that is based on the finite-element method is thus proposed as an alternative and more effective solution for computing casing centralization for cementing operations. Measured and calculated casing centralizations were compared in several field cases. The casing eccentricity was measured after the cement placement by use of recently developed ultrasonic logging tools and diagnostics. Discrepancies between analytical and numerical calculation methods were analyzed; then, advantages and disadvantages to each method were assessed. The results of the calculation methods were used to formulate an optimal approach to casing centralization.

Traditionally, service companies have had to place several consecutive cement plugs to successfully kick off wells deeper than 3,500 meters. Within the scope of integrated projects in Southern Mexico where wells are usually deeper than 5,000 meters, the low success rate for traditional balanced plug cementing has jeopardized operational efficiency and financial results. Several plug failures made it clear that the volumetric calculations and other known engineering best practices that were implemented were not sufficient to bring the success rate to an acceptable level. In our field study, we implemented an innovative simulation and design method that allows for engineered optimization of the plug placement design and that shows how a 100% success rate in plug cementing can be achieved in wells as deep as 5,720 meters, with hard formations and an OBM environment. The value of this new method resides in a live analysis and display of the fluid interfaces, mixing both while traveling down the pipe and up the annulus and resulting in the output of an estimated top of uncontaminated cement after pulling the pipe out of the hole. The new workflow reveals the effect of each variable affecting the amount of contamination of the cement slurry downhole and gives the engineer the opportunity to optimize the plug placement design before job execution to reach the highest possible top of uncontaminated cement after execution. The results obtained with the new engineering tool and a precise operational field execution has moved the theory of plug placement from the best practice library to the reality of the plug placement operations.