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.

Elastomers are widely used in downhole tools for oilfield applications and are often exposed to gases, such Carbon Dioxide (CO2), and Hydrogen Sulfide(H2S) in addition to the produced hydrocarbons and water. Successful drilling operations and reservoir management involve the use of tools of appropriate metallurgy and sealing materials. Depending on the environment (High Pressure High Temperature, H2S, CO2, or others), the sealing property of the elastomers may fail, leading to HSE (Health, Safety & Environment) and operational related incidents. Examples of such incidents are the undesired production of fluids, contamination of ground water, and the consequent loss of time and profits. Consequently, the selection of the sealing material used for downhole oilfield applications is critical and needs to be carefully considered, either for short-term drilling operations or for long-term completion activities. Elastomer compatibility studies covering a variety of media such as diesel, oil- and water-based muds, and brine are available in the literature. However, compatibility to super critical fluids like pure CO2 or H2S are not widely documented and even difficult to find in public domain. This paper describes a testing methodology to investigate the behavior of selected elastomers under CO2 environment at different temperatures and pressures. It focuses on the swelling behavior of different materials upon contact with CO2. Two testing methodologies are investigated. One is using a High Pressure High Temperature autoclave from "Parr Instrument". It allows samples to be simultaneously exposed to two different environments; the wet supercritical CO2 and CO2-saturated fluid. The second is using a High Pressure High Temperature Visio-Cell equipped with a high resolution camera. The benefit of such a set-up is that it allows a "real-time visualization" of individual particles while in contact with CO2. Results obtained show the HPHT Visio-cell to be the best fit for assessing the behavior of the tested material. Additionally, some components appear to swell less with CO2 than others.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractCleanout of proppants, cuttings and fines in well construction and production phases are typical of oilfield operations. To make these processes successful, extensive research efforts have been done on the development of (i) equipment such as concentric pipe, tubing-operated pump-to-surface bailer and coil tubing with jetting; (ii) engineering operation control and software simulation such as conventional high-rate circulation, reverse circulation, three-segment hydraulic modeling; and (iii) carrier fluids with suspension capabilities.The development of equipment is generally expensive, and often operation limited. Software simulation and control of operation parameters are normally not able to achieve the expected cleanout effectiveness due to the process complexity. Development of novel fluid systems is the only way forward to simplify the cleanout puzzle, and extensive research has been done to improve the efficiency of carrier fluids. The most commonly used fluids are brines, drilling fluids, foams and viscous polymer fluids.The paper describes the laboratory development of a novel viscoelastic surfactant-based cleanout fluid system and its successful field application. This fluid has several advantages over conventional polymer systems. Viscoelastic surfactant systems are non-damaging to the reservoir, has excellent suspension capacity, adjustable density for hydrostatic head and low friction.

Scale deposits are a common problem in oil and gas wells and can have detrimental effects on well production. Depending on the severity, scaling can stop production entirely as scale forms anywhere in the well production system, including the formation, perforations, casing or tubular, and in or on the artificial lift equipment. There are several chemical and mechanical methods for removing scale deposits. However, to prevent scale deposition, the only solution is chemical inhibitors injected into the formation. The typical production system includes artificially lifted, stimulated wells (propped hydraulic fractures) placed in reservoirs where pressure maintenance is achieved by water flooding. The artificial lifting is typically accomplished through use of electric submersible pumps (ESPs). In reservoirs where produced fluids exhibit scaling tendencies, ESP run life is significantly shortened by scale formation on the pump elements restricting rotation. By treating the formation with chemical inhibitors, the life of the ESP can be extended. In this paper we provide approaches for improving a compatibility of a novel hydraulic fracturing fluid (used in Russia) and scale inhibitor. A 3-year campaign to combine scale inhibition with the hydraulic propped fracture effectively increased the average run life of ESPs in the Mayskoe and Snezhnoe oil fields.