TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA self-diverting-acid based on viscoelastic surfactant (SDVA) has been used recently on stimulation treatments of carbonate formations. The new system has been proven successfull in more than 250 field applications. The decrease of acid concentration during the spending process viscosifies the fluid by the transformation from spherical micelles to an entangled wormlike micellar structure while penetrating the carbonate rock. The highly viscous fluid acts as a temporary barrier and diverts the fluid into the remaining lower-permeability treating zones. After treatment, the SDVA barrier breaks when contacted either by formation hydrocarbons or pre-and post-flush fluids. Quantifying diversion, fluid efficiency, and cleanup are important factors for successful candidate selection and job design. Laboratory tests defining these key factors are presented in this paper. This paper demonstrates the diverting ability of the acid as a function of permeability, characterized by introducing the concept of maximum pressure ratio (dPmax/dPo) supported by core-flow and acid conductivity tests using limestone and dolomite cores. Results demonstrate high dPmax/dPo in highpermeability cores and low dPmax/dPo in low-permeability cores. Retained permeability measurements are presented that assesses the level of cleanup. Flow initiation experiments of spent acid systems with gas and brine were performed to illustrate the cleanup behavior of SDVA in comparison to gelled acid systems under conditions encountered in gas and oil wells. The results indicate that SDVA systems clean up easily and that SDVA provides higher regained permeability than conventional gelled acid systems.

Summary A self-diverting-acid based on viscoelastic surfactant (SDVA) has been successfully used recently on numerous stimulation treatments of carbonate formations in various fields. The decrease of acid concentration during the spending process viscosifies the fluid through the transformation from spherical micelles to an entangled wormlike micellar structure while penetrating the carbonate rock. The highly viscous fluid acts as a temporary barrier and diverts the fluid into the remaining lower-permeability treating zones. After treatment, the SDVA barrier breaks when contacted either by formation hydrocarbons or pre- and postflush fluids. Quantifying diversion, fluid efficiency, and cleanup are important factors for successful candidate selection and job design. Laboratory tests defining these key factors are presented in this paper. This paper demonstrates the diverting ability of the acid as a function of permeability, characterized by introducing the concept of maximum pressure ratio (dPmax/dP0) supported by core-flow and acid conductivity tests using limestone and dolomite cores. Results demonstrate high dPmax/dP0 in high-permeability cores and low dPmax/dP0 in low-permeability cores. Retained permeability measurements are presented that assess the level of cleanup. Flow-initiation experiments of spent acid systems with gas and brine were performed to illustrate the cleanup behavior of SDVA in comparison to gelled acid systems under conditions encountered in gas and oil wells. The results indicate that SDVA systems clean up easily and that SDVA provides higher regained permeability than conventional gelled acid systems. Background The purpose of matrix stimulation in limestone and dolomite reservoirs is the formation of wormholes, which can bypass the damaged areas and increase the effective wellbore area. When acid enters the formation with the highest injectivity it creates highly conductive flow channels, called wormholes, by dissolving the carbonate-containing minerals. Consequently, the injectivity will be further increased. The other zones are left untreated by the acid. To overcome this problem, a diverting agent is used. Mechanical diverters such as ball sealers, degradable ball sealers, rock salt, and benzoic acid flakes are used alone or in conjunction with chemical diverters based on foams or polymeric gels (Williams et al. 1979; Economides and Nolte 1989). These materials can work effectively only in a narrow permeability contrast and may result in residual damage (Lynn and Nasr-El-Din 2001). These characteristics are highly undesirable, particularly in low-pressure gas wells, and in long vertical and horizontal sections. Polymer-based systems such as in-situ crosslinked gelled acids (XLGA) have been used in the field as self-diverting fluids. These systems rely on a pH-triggered increase of viscosity during the acid spending process. Essentially, the pH change activates a metallic reagent that crosslinks the polymer chains, and the resulting viscosity increase causes a higher flow resistance (Mukherjee and Gudney 1993; Saxon et al. 1997). Further increase of the pH deactivates the metallic crosslinker and breaks the fluid down to the original linear gel with dissociated polymer chains. However, because of the nature of the long polymer chains, potential damage of the formation may occur (Lynn and Nasr-El-Din 2001). Recently, a new polymer-free self-diverting acid system was developed with a fluid stability in temperatures greater than 300°F (Taylor et al. 2003; Chang et al. 2001). The fluid system has been applied successfully in both matrix (Al-Mutawa et al. 2001) and acid-fracturing (Al-Muhareb et al. 2003; Artola et al. 2004) treatments. It causes rapid viscosity development throughout the spending process. The reduction in acid concentration, together with the simultaneous release of ions in solution, promotes the transformation from spherical micelles into worm-like micelles, resulting in increased viscosity of the fluid. The highly viscous fluid subsequently diverts the remaining acid treatment fluid into zones of lower injectivity by reducing the acid loss into wormholes, resulting in an improved zonal coverage of the treatment interval. Diversion tests using multiple parallel cores with varying permeabilities showed effective stimulation in all cores (Taylor et al. 2003; Chang et al. 2001). This paper presents new data providing further insight into the understanding of the unique properties of this SDVA based on laboratory studies. Specifically described are the chemical and physical properties of the SDVA fluid, including cleanup efficiency that is relevant to low-pressure reservoirs.

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.

Offshore reservoirs requiring sand control pose a major completion challenge because of extremely high cost and risk involved in remedial treatments, particularly in sub-sea completion and/or deep-water environments. It is therefore of utmost importance to ensure sand control without sacrificing flow conformance, recoverable reserves and well deliverability throughout the expected life of the completion. A major trend in these environments is towards open-hole, horizontal, gravel-packed completions. Although gravel packing stabilizes the wellbore, it can also entrap the filter-cake formed by the reservoir drilling fluid, potentially resulting in high drawdown requirements (flow initiation pressures) and/or low production rates (retained permeabilities). The cleanup procedures in the industry have varied significantly from no cleanup at all to complicated two-stage breaker treatments involving post-completion coiled tubing intervention, with no guidelines existing in the literature. In this paper, we present experimental results and field cases involving filter-cake flow-back through gravel packs with and without cleanup. Effects of various parameters, including gravel size (40/60, 20/40, and 12/20), formation permeability, drill-solids type (clays, quartz) and concentration, and the type of cleanup fluid have been investigated. Flow initiation pressure and retained permeabilities during flow back are reported as a function of these parameters. The experimental results show that the flow initiation pressure is a strong function of gravel size and the type of drill solids. It is concluded that, in clean (low-to-no clay content) formations of large grains and high permeabilities (~ several darcies) requiring large gravel sizes (e.g., 12/20), an enzyme or an oxidizer treatment is sufficient based on laboratory results and productivity predictions. This conclusion is also supported by several field applications as shown. In lower permeability (~ 100–250 md) formations of small sand sizes requiring smaller gravel (e.g., 40/60) elimination of both the fluid loss control agent (starch) and bridging agent (CaCO3) is necessary based on high flow initiation pressures and low retained permeabilities. In intermediate permeability (~ 500–800 md) formations of medium size sand-grains typically requiring 20/40 gravel, the results depend strongly on the type of drill solids: in clean formations (no clays in drilling fluid), an enzyme or an oxidizer treatment is sufficient, while in dirty formations removal of both CaCO3 and starch is necessary. These results are also supported by field case histories presented in the paper. Introduction Gravel packing has been gaining wider popularity in open-hole horizontal completions where sand control is required, particularly in sub-sea completion and/or deep-water environment. The cost of intervention in such cases makes risk mitigation a much more pronounced task. Until recently, a large majority of horizontal sand control completions have utilized standalone screens. However, because a substantial fraction of these wells have failed prematurely (either productivity loss due to screen plugging or loss of sand control due to screen erosion),1 many operators have changed their primary completion technique in these wells from standalone screens to gravel packing. This is particularly true in formations containing a large fraction of non-pay (shale, mudstone/siltstone) and/or have a wide particle size distribution.2

Gravel-packing of open-hole highly-deviated or horizontal wells is increasingly becoming a common practice, especially in deep water and sub-sea completion environments where production rates may reach up to 50,000 BOPD or 250 MMSCFD. In these wells, reliability of the sand face completion, in addition to other factors, is of utmost importance due to the prohibitively high cost of intervention or side-tracking and the very high hydrocarbon recoveries required per well. To date the norm in gravel-packing such wells is water-packing or shunt-packing with water-based fluids. With both techniques, filter-cake removal treatments are conventionally done through coiled tubing after gravel packing, pulling out of the hole with the service tool and running in with the production/injection tubing. Furthermore, because conventional gravel-pack carrier fluids are water-based (brine or viscous fluids), water-based drilling fluids are traditionally used to drill the reservoir section to ensure compatibility and improve wellbore cleanup, even if the upper hole is drilled with a synthetic/oil-based drilling fluid. In this paper, we discuss several novel techniques that can substantially improve return on investment in gravel packing of open-hole horizontal completions, through reduced cost and process time, improved fluid management practices, increased productivity and/or reduced risk of future interventions, so mitigating against the risk of sand face completion failure or under-performance. The proposed techniques include:Simultaneous gravel-packing and filter-cake removal with water-based carrier fluids when the reservoir is drilled with a water-based drilling fluid: laboratory data relevant to gravel-packing are given and field case histories are discussed in detail.Simultaneous gravel-packing and cake cleanup with either water or a synthetic/oil-based carrier fluid when the reservoir is drilled with a synthetic/oil-based drilling fluid: laboratory data on cake removal while gravel packing are presented for both water-based and oil-based carrier fluids along with data on kinetics of cake removal.a new service tool that utilizes wash-pipe as continuous tubing and thus allows spotting of breaker treatments immediately after gravel packing: detailed description of the tool and its operation is given.Gravel-packing of highly-deviated or horizontal wells above fracturing pressure. Benefits offered by each of the proposed techniques are discussed in detail along with their current limitations. Introduction A great majority of the highly-deviated and horizontal wells are being completed as open holes, primarily because of their much higher damage tolerance, higher well productivities at high mobilities (kh/µ) and lower cost compared to cased holes. Although most of these wells in areas requiring sand control have been completed with standalone screens, a rapidly increasing fraction of them are now being gravel packed, particularly in deep water, high production rate and/or sub-sea completion environments (currently ca. 40%, and projected to be ca. 60% by 2003/2004). The major drivers for this current trend are the prohibitively high cost of intervention and much higher reliability associated with gravel packs.1,2

No abstract

Open-hole horizontal wells are increasingly used to improve reservoir exploitation and production rates by targeting specific zones and maximizing reservoir exposure. The drilling fluid of choice in many of these wells is "oil based" due to enhanced drilling rates with minimized friction as well as improved wellbore stability. However, in horizontal wells requiring gravel packs, the industry in general has been reluctant to use OB reservoir drilling fluids (RDF) for various reasons. Because the gravel pack (GP) carrier fluids that have been successfully used to date are all water-based and the use of OB-RDF would necessitate displacement of open hole to WB fluids prior to GP, the practice has been to switch to WB-RDF once in the reservoir section. This was due to concerns as to adverse fluid-fluid interactions resulting in sludging and difficulty in maintaining filtercake integrity while displacing OB-RDF in the open hole, leading to complex fluid management issues. An additional factor has been the perception that WB-RDF filtercakes are easier to remove should it be necessary, since most commonly used cleanup chemicals are water-based and the weighting/bridging agents used in the RDF are also water-wet if the RDF is water-based. In this paper, we present results from experiments conducted with OB-RDFs in the presence of gravel packs. We investigate two scenarios:the gravel pack carrier fluid is water-based, andthe gravel-pack carrier fluid is oil-based. In the first case, provided that no sludges are formed during displacement to water-based fluids, the retained permeabilities are comparable to or better than those obtained with WB-RDFs, although values lower than 0.04% can be expected in the presence of sludging. Another issue relevant to gravel packing wells drilled with OB-RDFs is the yield strength of their filtercakes in comparison to WB-RDFs. It is found through yield stress measurements of various RDF cakes that OB-RDFs have several orders of magnitude lower yield strength than their WB counterparts. This finding is consistent with the reported lower flow initiation pressures for OB-RDFs, and indicates that cake erosion during gravel packing is more likely with OB-RDFs. In order to optimize the sequence of fluids to obtain a good displacement of the RDF at field scale, we use a purpose-built numerical simulator. This simulator is a fluids mechanics code that can accurately calculate displacement fronts in field conditions: eccentric deviated annulus with as many fluids as necessary. Its main use is to detect unstable displacements such as channeling of the displacing fluid on the wide side of the annulus or slumping in horizontal portions. Furthermore, we provide data on a new oil-based gravel pack carrier fluid that can be used to eliminate fluid incompatibility and fluid management issues associated with the switch from OB to WB fluids. The laboratory and large-scale yard test results are presented, addressing critical considerations for oil-based GP carrier fluids. It is found that such emulsion systems can thicken or break (depending on the emulsifier concentration) at high shear rates unless the emulsion is made at the highest shear that it will be exposed to. The implications of these results on field practices are discussed along with recommendations on avoiding damage in gravel packed wells drilled with oil-based RDFs.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn this paper, we present a novel approach for drilling and completing open hole horizontal wells with a fully compatible synthetic/oil-based fluid system utilizing shunt tube technology. The proposed RDF is a synthetic/oil-external emulsion that is reversible through exposure to a fluid of pH less than 7. A surfactant package included in the RDF waterwets the bridging/weighting agents (e.g., CaCO 3 ) upon reversal of the emulsion. The synthetic/oil external emulsion developed for gravel packing typically contains 50-75% by volume aqueous phase as the internal phase and is completely solids-free. The internal phase can either be brine or a pHreducer as well as a fit for purpose dissolver for the bridging agents. The pH-reducing property of the internal phase provides the required break mechanism for the S/OB-RDF emulsion remaining in the RDF filtercake under leakoff conditions allowing the bridging agents and drill solids to be water-wet, ensuring dissolution of the bridging agents.Laboratory data are provided for filtercake removal kinetics as a function of temperature, overbalance during gravel packing, gravel mesh size, and drill solids concentration in the RDF. Rheological data are given. Retained permeabilities and flow initiation pressures measured with the combined core and gravel-pack system are presented. Implications of the laboratory results on field practice are discussed.