Successful acid stimulation requires a method for diverting an acid across the entire hydrocarbon-producing zone. Because most producing wells are not homogeneous and contain sections of varying permeability, being able to completely acidize the interval is a major problem. This paper describes the use of a new low-viscosity system that uses a relative permeability modifier (RPM) that diverts acid from high-permeability zones to lower-permeability zones and inherently reduces formation permeability to water with little effect on hydrocarbon permeability. This system has been used effectively offshore Mexico with success for more than two years. The cases presented in this paper show the first application in a low-permeability carbonate formation where oil production was increased significantly compared to previous traditional acid treatments using conventional diverters.
The other important feature of this work is that the downhole conditions were high-pressure/high-temperature (HPHT). Details from the jobs using this new RPM acid-diversion system will be presented showing pre- and post-job production results.
Matrix acidizing enhances well productivity by reducing the skin factor. The skin factor can be reduced if near-wellbore damage is removed or if a highly conductive structure is superimposed onto the formation. In either case, the result is a net increase in the productivity index, which can be used either to increase the production rate or to decrease the drawdown pressure differential. Although the benefits of an increased production rate are evident, the benefits of reduced drawdown are often overlooked. Decreased drawdown can help prevent formation collapse in weak formations, reduce water or gas coning, minimize both organic and mineral scaling, and/or shift the phase equilibrium in the near-wellbore zone toward smaller fractions of condensate or solution gas. A reduced drawdown pressure can also help ensure that a greater percentage of the completed interval contributes to production.1
In attempts to achieve uniform placement of acid across all layers, various placement techniques have been used.2 The most reliable method uses mechanical isolation devices (such as straddle packers) that allow injection into individual zones one at a time until the entire interval is treated. However, this technique is often not practical, cost-effective, or feasible. Without a packer, some type of diverting agent must be used.
Typical diverting agents include ball sealers, degradable particulates, viscous fluids, and foams. Although these agents have been used successfully, all have potential disadvantages and none address the problem of increased water production that often follows acid treatments. Therefore, it would be a major advantage to have a material that could inherently decrease the formation permeability to water while also providing diversion.
One method of controlling water production uses dilute polymer solutions to decrease the effective permeability to water more than to oil. These treatments may be referred to as relative permeability modifiers (RPM), disproportionate-permeability modifiers, or simply, bullhead treatments. The latter name is so called because these treatments can be bullheaded into the formation without the need for zonal isolation. RPM systems are thought to perform by adsorption onto the pore walls of the formation flow paths.3-5
Development of light-oil fields in Mexico is part of a strategic program to increase overall production in Mexico. Among the light-oil fields, operators have gas condensate carbonate reservoirs with medium permeabilities ranging from 3 to 10 md, with very high drawdowns. The initial development concern was how to make them produce above the bubble point. The first thought was to fracture the intervals to reduce the drawdown, but the permeability values from well tests made matrix stimulation appear acceptable. Some believe that with permeabilities in the 3 to 10 md range, fluid-loss issues may prevent reaching fracture pressure. In that case, a matrix treatment may be used, thus avoiding a more expensive hydraulic-fracture treatment.
However, step-rate test (SRT) results were unclear, so doubt remained. In three cases, permanent downhole sensors were available, and minifrac and fall-off analyses with downhole data were possible. Observation of the flow regimes in the data established a comparison of planned flow periods before and after the tests and frac jobs. If this data is used to help optimize treatment, applying frac treatments will be the best choice, and the investment will be justified. It was also observed that lower injection rates must be applied during the SRTs, starting from 0.5 bbl/min.
The operator concluded that "gray zone?? candidate wells with medium permeabilities can benefit from matrix treatments and fracture treatments.
Post-fracture evaluation shows that drawdown matches very closely to the flow prediction, and this kind of reservoir can be produced above saturation points.
In this paper, three successful case histories are discussed in detail.
May Field is the principal gas-condensate producing field for the light-oil project Offshore Mexico. Oil and gas production is constrained by (1) the skin factor, (2) the amount of drawdown due to the low-permeability effect and (3) the limited presence of open fractures. With small acid treatments, wells could produce an average oil rate of 1,800 BOPD and 8 MMscf/D, with an average drawdown of 6,000 psi, as a result of skin elimination. However, saturation pressure became a concern, because producing a reservoir with high drawdown can create condensate in the reservoir, causing oil blockage.
The purpose of this work is to present an alternate use of real-time data with permanent sensors, applying minifrac analysis and well test techniques to help optimize the way we perform stimulation treatments in medium-permeability gas condensate reservoirs, i.e. "grey-zone stimulation candidates.??
May Field is a gas-condensate reservoir located 30 miles north from Dos Bocas, Tabasco, Mexico. It is part of a strategic program for light-oil production. May Field produces from Cretaceous and Jurassic formations with average thickness of 380 m. The limestone is compact and very clean with small sealed fractures and fissures, and is at a depth of 5,500 m. The average permeability is 3-8 md. The initial reservoir pressure was 11,715 psi, with a reservoir temperature of 176°C. The dew-point pressure is 5,623 psi, and the initial condensate gas ratio (CGR) was approximately 205 bbl/MMscf, and the gas oil ratio (GOR) was 890 m3/m3.
Early wells showed almost 60% of energy losses across the formation; initially it was blamed to skin. Skin factor with these permeabilities can be moderated between 20 and 50 (dimensionless).
After several attempts to enhance production using matrix treatments, the first questions were: (1) How to optimize and enhance treatments? (2) Should fluids be changed? (3) Would rate increases be beneficial to the treatment? (4) Can the formation be broken with such high rate admissions?