No abstract

The Mexico South Region produces more than 520, 000 bopdl from mature carbonate reservoirs. These reservoirs have widely varying reservoir pressures, presence of natural fractures and temperatures up to 350 degF. The extremely high temperatures makes even more challenging the stimulation process with conventional systems resulting in excessive corrosion and very inefficient wormholing. An innovative solution, considering a chelating agent as treating fluid, has proved to be an effective approach to stimulate these reservoirs. The post treatment production in two different wells showed outstanding results with higher rates than previous treatments and the trend of the production declination was smoothed. This new stimulation solution aided with a good candidate selection has led it to be the preferred solution for HT wells. Well A was treated with 15.0 m3 of the fluid based on chelating agents as main system, with a solvent preflush and overflush. Previous to this job two stimulation treatments were performed pumping a mixture of conventional acid systems. In both occasions the production increased, however, the production declined to pre-treatment rates in a matter of days. When treated with the new solution the production increased 254 bpd with almost no decrease with time (monitored for three months), indicating a more efficient stimulation treatment, and greatly improved on the economical indicators. Well B was stimulated with 20.0 m3 of chelating agent fluid after three previous attempts using conventional systems. The production increased 726 bpd. Post-treatment behavior was the same as well A. Wells A and B showed an increased production of 1.7 KBD with a very limited production declination because of more efficient wormhole creation due to retarded reaction rates allowing a wide contact with the reservoir thus improving production performance, Np and eliminating post-treatment neutralization and testing surface equipment requirements.

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.