This paper documents efforts to seek alternative and effective treatments for stimulating wells in southern Mexico. It was desired to make treatments more selective, stimulating only areas of oil without contacting contributing areas of water or gas. Stimulation treatments were performed using coiled tubing (CT) and a fluidic oscillator to generate waves of fluid.In the southern region of Mexico, the commercial production of hydrocarbons is in reservoirs that are naturally fractured carbonates with permeability of 25-150 mD, porosities of 5-15%, and are depleted as a result of exploitation. Also, the progress of oil-water contact and gas-oil contact present challenges when designing treatments for stimulation.The damage mechanisms encountered in these wells included blockage by water, paraffin, asphaltenes, and scale depositions, which were generated in the near-wellbore area of the well.To enhance the effect of the stimulation systems, the fluidic oscillator was used to generate a frequency of impact of 300 to 600 Hz on the formation, weakening the damage and efficiently removing it.Commonly, in the southern region of Mexico, 90% of the stimulation treatments are bullheaded; however, in highly deviated wells with two or more pay zones, the use of CT with the fluidic oscillator offers an alternative to increase the effectiveness of acid placement.The synergy of CT, the generation of fluid waves, and the selection system for optimal acid flow through each hole have led to significant results of reduced cost, time, and, in turn, optimizing the volumes of systems required to stimulate wells.In this paper, results achieved by carrying out selective stimulation treatments as well as technical and economic benefits of using CT and the generation of fluid waves as an alternative stimulation treatment for oil wells are presented.

The well used for this study, 301, was originally considered "un-drillable". A steep pore pressure ramp combined with loss zones resulted in a cross-flow environment that was very difficult to control, as the drilling window was effectively reduced to less than 0.09g/cc. The ability to precisely control the pressure profile in the annulus is one distinct advantage of Managed Pressure Drilling (MPD). In worst case scenarios with very narrow pore pressure and fracture gradient windows, the tight drilling margin may require the use of an automated MPD system. The system can precisely apply surface back pressure to maintain a balance of flow into and out of the well by maintaining a constant bottom hole pressure and replacing the friction pressure losses in the annular space when the rig pumps are off.During the execution of the well 301, all Automated MPD benefits were applied (Dynamic FIT's, Dynamic Flow Checks and CBHP control) to detect and control kicks, identifying and control ballooning effects and maintaining the bottom hole pressure within the high pressure tight window between 2.426 and 2.451 g/cm 3 . Proper selection, configuration and continuous calibration of the hydraulics simulations during drilling operations was critical to drill the production section and successfully reach target depth. This paper presents the hydraulics modeling during the planning phase and techniques used during execution with the automated MPD system. Following two previous failed attempts, the 301 well was the first successful well to penetrate the reservoir in the Camaronero field, proving automated MPD as a successful drilling technique for this field.

With the discovery of new fields becoming less common and the need to maximize economic recovery in mature fields, operators are trending towards rig-less intervention work to reduce cost and delays to production related to traditional workover rig interventions. With its field complexities, from low bottom hole pressure (BHP) to high temperature/high pressure (HT/HP) reservoirs, and from consolidated sandstone to naturally highly fractured carbonates, and large producing intervals in various flow units with active aquifers, southern Mexico poses a highly significant challenge for rig-less intervention in water control and zonal isolation to assure placement and accuracy of treatment fluids. This paper discusses the implementations and results of two case histories in which a cost-effective application involving coiled tubing and inflatable packer systems were used for water control in a high water cut producing well and for well abandonment of a newly completed well. The utilization of coiled tubing combined with the inflatable packer is able to precisely deliver the treatment fluids to the zone of interest while the production tubing remains in place, which enhances timely and cost effective intervention solutions1 when compared to workover rig operations. Case 1 presents the water control application using a coiled tubing inflatable packer system in combination with an organic crosslinked polymer gel, and micro-fine cement slurry for a naturally fractured carbonate reservoir in southern Mexico. The result of this innovative rig-less approach exceeded the operator's expectations. The case history well was producing 815 BOPD and 5.2 MMSCFD with a water cut of 77%. After the water control treatment with the coiled tubing inflatable packer system, organic crosslinked polymer gel and micro-fine cement slurry, the well was producing 1,459 BOPD and 5.15 MMSCFD with a water cut of 0%. Case 2 demonstrates a newly completed well with production tubing and packer already set and the well producing with high water cut from an open-hole completion. By using the inflatable packer system through coiled tubing and squeezing cement slurry to abandon the open-hole, a new interval could be perforated and exploited in just 28 hours; in contrast, conventional abandonment with a rig can take up to 10 days.