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.

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.

A life-of-well comprehensive methodology for production optimization is demonstrated through two Gulf of Mexico stimulation treatments in formations requiring sand control. The approach considers the full well history in the process of well evaluation and candidate selection. The treatments were designed for remediation of damage caused by a time-dependent disruption of formation sand and/or sand-control mechanism, including fines migration, proppant instability, and scaling. Traditionally, data from permanent bottomhole gauges have been used as a valuable tool for well and reservoir management. As demonstrated in this paper, the data can be crucial to the assessment of the evolution of time-dependent skin. The practical result of well or reservoir surveillance and diagnosis from permanent gauge or traditional production data is shown to produce better decisions on stimulation and production management, while maintaining life-long well integrity. Introduction Completion optimization for sand control has been discussed in the literature by several authors.1,2 This paper deals with the identification and the remedial actions to reduce or remove completion damage associated with sand control for wells with and without permanent downhole pressure gauges (PDGs). With the balance required between the value of imformation and the overall economics of a development and exploitation project, it becomes extremely important to capture all events during the life of a well and to utilize all information to the fullest extent. The use of high-frequency data or continuous information has a great impact in the expansion of the traditional time scale, from the usual snapshot approach to a continuous evaluation and remedial action process. This process can lead to real-time production managemement and decision making. The integration of historical well information from different sources and continuous or high-frequency data, and their availability for practical use through proper evaluation tools, remains a challenge. However, the lessons learned are quickly developing a knowledge base that can greatly impact well and reservoir management in the future. Life-of-Well Approach Several factors play significant roles when dealing with completion decisions, especially in the offshore and deepwater environments. The feasibility for any development project rests not only on available reserves but also on the longevity and integrity of well completions. Critical early time and baseline well fingerprinting information is sometimes not available, or not recorded, which can significantly impact the decision-making process on all downstream operations. This situation is equally applicable to single- and multiwell cases. Completions requiring sand control are especially prone to time-dependent degradation due to the evolving formation and proppant mechanical conditions, which at the end impairs hydrocarbon production through the gravel pack and/or frac-pack elements. It is extremely important to be able to forecast realistic dynamic operating well conditions when planning a sand-control completion. Planning enables the selection of the most appropriate completion method, including the corresponding hardware configuration and job execution program to achieve the expected results. Fig. 1 presents the life-of-well approach for completion and production optimization. This continuous, perennial process is initiated at the early exploratory and development stages and continues until depletion and abandonment. Below is a brief description of the basic elements of this approach. WCP Forecast The life-of-well process begins with the well completion productivity (WCP) prediction that uses all reservoir static and dynamic information. The data are fed into the reservoir module of the predictive model, which will also include information about heterogeneity, lateral extent, and expected drive mechanism. In unconsolidated formations and/or those with stress-dependent porosity and permeability, a sand prediction model and a geomechanical model may be needed on a sandface or regional basis.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes new methods to economically improve production levels in one of the mature fields of Petroleum Development Oman. This field had been developed by infill drilling programs, which were suspended in early 2001 to review the development strategy. A reservoir management team set a challenge to effectively conduct logging operations and quickly utilize the data collected to identify and avail of optimization opportunities, thus maximizing the production of the wells whilst lowering overall costs. The optimization activity consisted of clean-out, saturation logging, perforation and stimulation. These activities were carried out either with coiled tubing only utilizing conventional practises and e-line coiled tubing, or with the combination of coiled tubing and hoist through multiple well entries. Both of these methods were successfull in that they resulted in incremental net oil production but at relatively high costs. This paper presents a methodology which enables clean-out, logging, stimulation and perforation with one coiled tubing intervention, which includes a plastic coated "e-line" coiled tubing, coiled tubing perforating head and new perforation technology. All systems are in complete compliance with the most stringent safety criteria. The new method has a considerable time and cost savings impact, and this is fully illustrated in this paper with field trial case histories, in which a multi-disciplinary team effectively targeted the most suitable zones for perforation and stimulation using a state of the art self diverting, non damaging, acid system. Technical and economic comparisons are made with conventional practices. The methodology is currently being employed in this field and is potentially applicable to other fields.

This paper describes new methods to economically improve production levels in one of the mature fields of Petroleum Development Oman. This field had been developed by infill drilling programs, which were suspended in early 2001 to review the development strategy. A reservoir management team set a challenge to effectively conduct logging operations and quickly use the data collected to identify and avail of optimization opportunities. The ensuing campaign resulted in maximizing the production of the wells whilst lowering overall costs. The optimization activity consisted of clean-out, saturation logging, perforation, and stimulation. These activities were initially carried out in two ways: 1) with coiled tubing using only conventional coiled tubing and e-line coiled tubing or 2) with the combination of coiled tubing and a hoist. Both methods involved multiple well entries. Both of these methods were successful in that they resulted in incremental net oil production but at relatively high costs.This paper presents an enhanced methodology which enables clean-out, logging, stimulation, and perforation with one coiledtubing intervention, which includes a plastic-coated "e-line" coiled tubing, coiled-tubing perforating head, and new perforation technology. All systems are in complete compliance with the most stringent safety criteria. The new method has a considerable time and cost savings impact. These results are fully illustrated in this paper with field trial case histories, in which a multi-disciplinary team effectively targeted the most suitable zones for perforation and stimulation by use of a state of the art self-diverting, nondamaging, acid system. Technical and economic comparisons are made with conventional practices. The new methodology is currently being used in this field and is potentially applicable to other fields.