It has been observed that pumping a mini-frac prior to a TSO Frac-pack can impact the effectiveness of the frac-pack. The calculated fluid loss parameters determined in the diagnostic test are often not valid for the main fracture design due to the residual effect of the mini-frac and/or step-rate fluids. A technique will be presented in this paper which allows the calculated fluid loss parameters from the diagnostic test to be used reliably without excessive waiting time for the reservoir to recover to its original leak off characteristics. Fifty plus treatments were evaluated to develop a technique which makes this possible. The use of this technique resulted in a significant change in the success of the TSO designed treatments - success being a TSO type pressure increase while pumping. The success rate to achieve designed TSO, by incorporating the changes described in the paper, was increased over 20 percent with a reduction in time between diagnostic tests and the main frac. In the wells associated with this paper, a borate-crosslinked fluid was used for a mini-frac treatment followed by a step-rate test prior to the main proppant laden frac-pack. The fluid was designed with minimal polymer loading for the well conditions. The resulting mini-frac tests had low fluid efficiencies. It was originally thought that using this fluid, followed by injection of a linear step-rate fluid, would minimize the changes observed in fluid efficiency between the diagnostic test and the main fracture treatment. However, the effect of the diagnostic test on fluid leak off still resulted in less than desired TSO predictability. A technique of adding a pH control additive into the final portion of the step-rate test fluid was found to successfully allow the use of the observed diagnostic test results, honoring the efficiency from the mini-frac test. The quantity and placement of the pH control agent in the step-rate protocol were dependent upon well conditions. The waiting time between the diagnostic test and the main treatment was reduced since a positive, controlled change was applied. The optimum pH reduction for the desired effect was determined in the laboratory and designed into each treatment depending upon well conditions.
Acid fracture conductivity experiments provide information valuable to effective design of acid fracture stimulation treatments in carbonates. They are complex tests, and a number of procedural details must be taken into consideration in order to upscale results to an adequate representation of well-scale acid fracture behavior for well productivity predictions. This paper focuses on a study performed on analog, quarried limestone core samples and a small number of reservoir core samples from the Unit 2 formation of Kazakhstan's Tengiz field to understand the impact of different acid fluid systems and procedural steps on acid fracture conductivity. The physical structure of the etched channels is observed to be impacted by the nature of the fluid and has a strong impact on the conductivity. The quality and uniformity amongst the core samples has a critical impact on the measurements and is assessed. The residence time of the acid in the acid-etched experimental channel is small, and the equivalency of acid volumes injected at the experimental scale to the large acid volumes injected into a well-scale fracture channel is considered. Special consideration is given to the procedure of applying stress to and measuring conductivity of the experimental acid fracture channel which may result in large-scale mechanical failures of the core sample, preventing a high-quality measurement of conductivity following injection of a closed fracture acidizing stage. This body of work discusses the design options and challenges which play a role in defining the testing strategy for an acid fracture conductivity study. Results demonstrate that with selection of appropriate fluid systems, acid fracture conductivity can be retained up to a closure stress of 6,000-7,000 psi in the Tengiz Unit 2 reservoir. A modified stress ramp-up procedure to improve closed fracture acidizing conductivity testing results obtained through the testing program is presented.
Nitrogen (N2) and Carbon Dioxide (CO2) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The Pilot-scale Foam Test Facility (PFTF) used in these investigations is first described. The PFTF is capable of generating foamed fluids at pressures up to 7,500 psig and at temperatures in excess of 300°F. Then, results from several investigations aimed at proving NG foam at conditions relevant to the field are presented. NG foam was characterized using rheology measurements and flow visualization techniques. Experiments were performed to investigate the texture and stability of NG foam generated by two different mixing methods: one using a custom designed tee to match mixing velocities in the field where the gas phase is jetted into the aqueous stream, and another to ensure comprehensive mixing for laboratory analysis. Parametric studies were conducted to explore the effects of flow rate, foam quality, and temperature on the stability of NG foam. Moreover, different fluid preparations were used to investigate the effect of base fluid and additive concentrations on the stability of NG foams. Additional laboratory studies that investigated foam stability with produced water and multicomponent NG mixtures are also reported. The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N2- and CO2-based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.
Sandstone acidizing operations usually include solvent and acid preflush, main acid treatment, and post-flush stages. However, the acid preflush stage needs good design and execution to prevent formation damage. Moreover, multiple-stage operations require large-volume fluids and pumping time. Therefore, it is challenging to stimulate sandstone formations, especially those with high clay and carbonate content. A novel single-stage acid has been developed to overcome these challenges and improve the stimulation success rate in a cost-effective manner. The application of the new acid system has been studied in laboratory testing. Core flow tests were performed to evaluate the stimulation performance with Berea Gray and Bandera Gray from 160° to 300°F. An inductively coupled plasma (ICP) instrument was used to analyze the ions in the spent acid effluent. The performance was compared with mud acid and organic mud acid. The acid-rock reactions were studied by batch reactor tests. Compatibility with crude oil and mutual solvent was also tested. The results of core flow tests have shown that the new acid was used to treat the sandstone cores effectively at temperatures from 160° to 300°F. The regained permeability range varies from 115% to 400% under different conditions. The new acid provided similar or better performance compared with the combination of acid preflush and mud acid or organic mud acid. High concentrations of Al and Si were observed in the spent acid effluents by ICP analysis, indicating the high dissolution capacity of clays by the new acid. The new acid is highly compatible with carbonate, which was supported by the high concentrations of Ca and Mg in the spent acid. Both core flow tests and batch reactor tests have shown that the new acid stabilizes the problematic ions (Al, Ca, Mg and Fe) in the spent acid. The new acid is compatible with mutual solvent from the core flow tests; therefore, the mutual solvent preflush can be eliminated. The new acid also has good corrosion control due to the relatively high pH compared with mud acid. Overall, the new single stage acid has been used to stimulate the sandstone cores successfully without acid preflush and solvent preflush. A differentiating characteristic of the fluid is that it greatly reduces the risk of treatment failure by reducing primary, secondary, and tertiary precipitation, while maintaining high dissolving power for clays. It uses a different, more cost-effective chemical pathway to stabilize problematic ions compared to traditional single-step sandstone acidizing systems. The new fluid simplifies operation by reducing the total treatment fluid volume, the total number of fluid stages, and the number of fluid types needed at the wellsite.
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