Water production represents a major challenge over the life of a reservoir. It is an important issue that directly affects hydrocarbon production and total reserves recovery around the world, especially in fractured reservoirs. In the south of Mexico, several naturally fractured, low-pressure reservoirs experience production disruptions when water from the aquifer channels invades oil-producing intervals through high-conductivity fractures. Water shutoff (WSO) treatments vary in design approach and efficacy percentage due to the difference in environments and formations that are subject to water breakthrough. For the last decade, in southern Mexico, different treatments have been performed without achieving the expected results in the described reservoirs. These treatments have included different types of fluids, including rigid setting gels; reactive pills; selective water setting cement; and conventional cement slurries, with or without the use of mechanical aids such as mechanical plugs, cement retainers, or coiled tubing for precise placement. One of the biggest challenges of WSO in these reservoirs is that the proposed treatments must have a high level of penetration into the natural fractures but, at the same time, they need to be displaced with nitrogen or light hydrocarbon derivatives to balance reservoir pressure, avoiding total losses of fluids into the highly conductive, low-pressure reservoir where they will lose the ability to control water flow from the aquifer. Using the synergies of the operator's reservoir knowledge, diagnostic workflow, and historical treatment records coupled with service company's treatment engineering technologies and local ability to manipulate and enhance existing WSO fluids, we exercised a systematic evaluation approach to the evaluation of past unsuccessful experiences and proposed adjustments to conventional treatments using rigid gel and conventional cement slurries for water control. Integrating the relevant findings following operator's water control diagnostic workflow with the study of relevant papers and methodologies used by oil companies around the globe, we proposed a different treatment strategy consisting in the addition of a reactive pill between the rigid gel and the cement to keep the treatment in the vicinity of the wellbore, viscous spacers between each treatment fluid to avoid contamination while traveling downhole, the inclusion of lost circulation fibers to create a fibrous net to promote cement filter-cake development and tailored treatment displacement with a predefined pressure according to reservoir condition that is close to the reservoir-equivalent hydrostatic pressure. During the past 2 years, the application of rigorous evaluation of potential candidates and the combination of these three enhanced WSO fluids in the described sequence reduced unwanted water production in two naturally fractured low-pressure reservoirs. In three field cases, the use of the proposed methodology led to a reduction of overall water production from an initial value between 70 and 100% to levels below 30%. Incremental oil production has been maintained in the best cases for more than 2 years after the treatments. The most significant result occurred in the first field case, where the water cut was reduced from 90% to less than 2% and oil production increased 12 times, obtaining a cumulative oil production of 240,000 bbl in a year. The documented methodology is a work in progress; we cannot replicate the technique exactly because each well presents challenges according to its construction and structural placement. Similar WSO treatments have been successfully applied in several wells in southern Mexico, increasing oil production and recoverable reserves. Continuous improvement efforts have also led to efficiency enhancement over time, as results and lessons learned are captured to be shared and replicated in similar reservoirs.
In carbonate reservoirs, reactive matrix stimulation creates highly conductive channels, which improves hydrocarbon production. Hydrochloric acid is widely used as stimulation fluid; however, its efficiency at high temperature ranges is limited. Other systems, such as organic acids or chelating agents, are used due to their slow reaction rate in hot carbonates; however, they cannot achieve the same volume of rock dissolution per unit of treatment. Seeking to optimize the stimulation process in "T" field in Mexico, the impact delivered by the introduction of a single-phase retarded acid in the stimulation workflow is presented in this paper. A change in completion architecture in "T" wells using slotted liners in the production pay zone is leaving exposed lengths in the carbonates in excess of 200 m, triggering early reaction with the treatment systems. This situation requires the use of reactive and divergent systems that will not spend quickly when in contact with the formation wall to ensure their full strength is used in the productive zones. Based on compatibility and reaction-rate laboratory tests, it was considered to add single-phase retarded acid as the main treatment system to improve the dissolution profile in the producing zone and reduce the reaction in the formation face. With the help of advanced simulation software, longer complex wormholes were modeled for given reservoir conditions, increasing confidence in the fluid selection described in the case study. The single-phase retarded acid showed improvements in production results in "T" field wells with new architecture. The production increase—approximately 25% after treatments in selected wells—were higher when compared to organic acid treatments. This is in part derived from improved wormhole efficiency (as tested and observed in laboratory), coupled with the higher dissolution power. The selected fluids have better solubility and controlled reaction rates, which allowed optimizing the treatment volume, thus helping to increase the profitability of the stimulation treatments in this field. Single-phase retarded acid exhibits a dominant wormhole regime for a wide range of injection rates due to its slow reaction rate. This greatly helps to accomplish the goal of being in a dominant wormhole regime. Having a dissolution capacity practically equal to hydrochloric acid and higher than that of the organic acids or chelating agents allows the optimization of stimulation treatment volumes. The retardation efficiency of this system is equal to that of emulsified acids, while it has a significantly less friction pressure profile and many other operational advantages, allowing more flexibility during job execution to pump at the optimum injection rate. Additionally, the ease of mixing and simple quality control result in faster well delivery and increased system stability at ambient conditions.
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