The stimulation history in offshore Brazil is undergoing into a deep transformation. The requirements of technology, before focused on sandstone reservoirs demand, are being expanded by the need for techniques to stimulate carbonate reservoirs, specially the pre-salt carbonates. In this scenario, a self-diverting acid system based on a viscoelastic surfactant (VES) technology was introduced for carbonate reservoir stimulation. The Self-Diverting VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. The mechanism of viscosity development is simple: In concentrated acid, the system presents low viscosity, which results in friction reduction while pumping; however, when the fluid reacts with the formation and the acid concentration decreases, the micelle spherical structures combine, transforming into rod-like micelles that convert to a 3-D structure, which increases the fluid viscosity. The high viscosity generates a temporary barrier across the high-injectivity zones, diverting the subsequent fluid to treat other reservoir zones. Generally the SD-VES is associated with several placement techniques that aid in achieving good treatment distribution through the entire producer interval. Regardless of the placement technique applied, the SD-VES is generally used as the main acid fluid and is bullheaded into the well. Because of its rheological behavior, the SD-VES is pumped as a single fluid during bullheading, aiming to achieve formation stimulation and good treatment distribution throuth the entire productive interval. Since the SD-VES was introduced in 2009 to treat carbonate reservoirs in offshore Brazil, more than 40 wells have been treated using the system in the various acid placement techniques presented in this paper. Three case histories are presented to better illustrate the different scenarios where the SD-VES was applied.

The Horizontal Open Hole Gravel Pack (HOHGP) is the preferred completion method employed in Campos and Espirito Santo basins, offshore Brazil. To pack the well, the proppant is pumped such that the alpha wave is propagated from the heel to the toe of the well and the beta wave then propagates from the toe to the heel. During the alpha and beta waves, the carrier fluid is diverted into and must travel through the narrow annulus between the screen base-pipe and wash-pipe to the toe, where the perforated base pipe is located. This diversion raises the friction pressure significantly. When pumping the beta wave, the friction rises even more because the fluid must travel through the gravel placed during the alpha wave before it can flow through the screen. The surface pressure required to overcome this high friction pressure can reach or exceed the formation fracture pressure, resulting in early termination of the gravel pack placement due to severe fluid leakoff to the formation. Some solutions are available, but the preferred method of dealing with pressure increases when performing HOHGP offshore Brazil is the ultra-lightweight (ULW) proppants and BOP open (return through the flow line). However, in some cases when the extended horizontal section is associated with a low fracture gradient and washed out zones, the pumping window expansion provided by ULW proppants and BOP open can be still not enough to perform the job comfortably. In such scenario a friction pressure reducer (FPR) was introduced to avoid pressure increases while pumping the gravel pack. The FPR can also minimize friction pressure increases in wells packed using intermediate-density ceramic gravels. This paper describes 3 successful case histories of circulation tests and HOHGP performed with FPR added to the completion fluid. The focuses are the challenges faced, lessons learned and advantages of using the FPR to extend the safe pumping window.

An extended-reach, S-shaped appraisal/development well drilled from a platform to prove up and drain a field extension in a Rotliegendes sandstone reservoir has been hydraulically fractured with a proppantbased stimulation treatment. The hydraulic fracture was a means to optimise the production rate and involved an injectivity test followed by a main treatment.The hydraulic fracture was performed utilising a stimulation vessel constructed in 2013 that is equipped to perform large-scale acid and proppant hydraulic fracturing and acid matrix stimulation treatments. This treatment was the first massive proppant hydraulic fracturing operation performed by the vessel. Prior to this operation, the vessel had been used to perform numerous acid-based stimulation operations.A total of 365.3 metric tonnes (730,536 lb) of resin-coated intermediate strength proppant was placed in the fracture, which is thought to be the largest single fracture treatment ever pumped in this particular national sector of the southern North Sea. A tip-screenout design was successfully used to achieve a high average proppant concentration of 23 kg per square metre (4.7 lb/ft 2 ), which equates to an average propped width of 1.3 cm (0.51 in). The large width was needed to achieve sufficient fracture conductivity for the expected reservoir permeability and to minimize convergent flow pressure drop in the fracture, due to the short perforated interval that was used. A very short perforated interval was used to minimize the risk of near-wellbore problems, due to the well deviation of 40 degrees in the payzone. This approach was successful, as the treatment was pumped as per program with no vessel NPT and no HSE incidents.Lessons learned included optimisation of perforating operations, methods to better optimise initiation of proppant flow to the blender, rationalising data sources, and effective use of equipment redundancy to ensure zero NPT.

Generally, offshore horizontal producer wells in Brazil do not require acid treatments after a gravel pack. The drill-in fluids' filter cakes have low lift-off pressures and are readily produced through the gravel and the screens. Injection wells, however, require acid treatments to break down the filter cake and establish low skin factors and favorable injection profiles.