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Many oilfields in southern Mexico produce from naturally fractured carbonate reservoirs with a high water cut. The majority of the remaining reserves are in the formation matrix. The objective when stimulating these wells is to connect the formation matrix with existing fractures. However, in some cases, the water-oil contact is close to the producing interval and the salinity of the water is more than 350,000 ppm. This results in rapid scaling and loss of production. The time for the scale to plug the well is a function of the volume of water produced.The challenge in these wells is not only to selectively divert the treating fluid away from the natural fissures/fractures-thief zones-invaded with water, but also to reduce water production from the natural fractures and fissures after the treatment. To treat the formation matrix, the diverter fluid must reduce the high permeability of the water-saturated intervals without impairing the permeability of the oil-producing intervals.Historically, in southern Mexico, viscoelastic surfactants have been used as main diverter for acidizing treatments. However, these systems have been successfully implemented in other applications. The surfactant also acts as a disproportionate permeability modifier (DPM) as the water cut is reduced after the treatments. The water cut of wells stimulated with treatments including the surfactant-based diverter remains below 10%, and the wells typically produce over 1,000 BOPD for more than 200 days before the scale has to be removed. The water cut of wells treated conventionally in the same field is typically above 60%, and the wells produce for fewer than 50 days after being treated before plugging with scale. The ability of the solids-free surfactant-based diverter to limit water production has made possible developing a field that previously was considered uneconomic due to the saline precipitation into the formation. Overview of ScalingScaling can be a serious problem for the oil and gas industry (Zhang et al, 2015). Scaling is the deposition of a mineral salt on processing equipment, and it is considered a result of supersaturation of mineral ions in the process fluid. This supersaturation of ions is caused by several factors (Nergaard and Grimholt 2010).
Fluid allocation is a common challenge in the stimulation of naturally fractured reservoirs in offshore Mexico. Multiple or large pay zones with thief intervals can cause preferable fluid admission to such zones. Using distributed temperature sensing (DTS), fluid-treatment distribution can be monitored in real time for this type of reservoir, and modifications can be made on the fly to improve fluid coverage. Monitoring with DTS can help optimize treatment economics and improve productivity. A reintervention to increase production in naturally fractured reservoirs involves improved stimulation schedules and the use of diverters to achieve fluid distribution across perforated intervals. Variable permeability and a potential for heterogeneous zones in the reservoir are a challenge for these types of wells. This document discusses a treatment performed to successfully stimulate a four-interval well using DTS measurements to monitor placement in real time. A gas-lift test was also performed during the monitoring operation to help identify the producing zone before the main stimulation began. The information gathered during the treatment helped the operator understand the production behavior of the well and acquire additional information for upcoming treatments. During the well intervention, the following information was obtained to help determine the success of the treatment: Fluid allocation was verified during and after injectivity testing (including differential temperature gradient) to help determine initial admission zones. This information enabled an appropriate schedule to be designed for the acid treatment.A gas-lift mandrel was used, and the zone contribution was qualitatively evaluated during this test.The stimulation treatment and the diverter stages were monitored in real time. The percentage of admission was calculated for each open interval, and a correlation using previous production-logging-tool data was performed.Early flowback of the well was observed. The production expected from the treatment was 800 BOPD. The stimulation treatment was considered successful, with an initial production of 1,050 BOPD (a 31% increase from the target). The information gathered during this treatment can also help modify upcoming treatments in the wells of this field with similar characteristics. Combined pre-treatment production monitoring and monitoring stimulation treatments in naturally fractured reservoirs using DTS helps identify the main producing zones and improves stimulation fluid distribution into lower-permeability intervals. This technique allows for performing treatment changes on the fly to attempt to achieve better zonal distribution and increase the productivity index in the wells.
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