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Conformance-polymer systems have been successfully applied for many years to control undesired water production from hydrocarbon wells. However, currently available polymers present a number of limitations for high-temperature wells (>250°F) in terms of providing longer gelation times and acceptable thermal stability. This paper presents the successful field implementation of an organically crosslinked polymer (OCP) for high-temperature applications in southern Mexico. The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 450 jobs have been performed with the OCP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel pack isolation, fracture shutoff, and/or casing-leak repair. Originally, the OCP system had a limited working temperature range from 100° to 250°F. The upper placement temperature of the system was ~250°F because, above this temperature, pumping times were too short. A recently developed carbonate retarder allows reasonable placement times up to 350°F, without the need for cooling down the formation to obtain enough pumping time. The retarder is not detrimental to the thermal stability of the system. An overview of case histories that used OCP in southern Mexico is presented in this paper. In addition, the development results of the high-temperature conformance polymer are discussed in terms of (1) gelation-time measurement and (2) effectiveness to limit permeability to water and thermal stability in sandpack flow tests at elevated temperatures. To date, more than 70 jobs have been successfully performed worldwide with the OCP at temperatures higher than 250°F. Introduction Excessive water production from hydrocarbon reservoirs is one of the most serious problems in the oil industry. Water cut greatly affects the economic life of producing wells. Unwanted water production is estimated to cost the petroleum industry about $45 billion each year, although accurate records of water production are difficult to obtain (Conformance Technology Manual 1996; Curtice and Dalrymple 2004). The southern region of Mexico presents a major challenge with water management as well. Water production results in extra disposal costs, scale buildup, reduced oil production, and eventually well abandonment (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid excessive water production, even when intervals still retain large volumes of recoverable hydrocarbons. Although natural fractures have a positive effect on oil flow, they also negatively impact water and/or gas flow caused by coning effects or high-permeability streaks between the producing hydrocarbon zone and intervals above and/or below. If these zones contain high mobile-water saturation, they soon will impact the productivity of the hydrocarbon zone. Early water breakthrough caused by edge-water flowing through faults or natural fractures is another common problem in this region. In addition, many of these formations with high-water-management problems produce from intervals with bottomhole temperatures higher than 250°F, hence the need for a high-temperature, porosity-fill sealant in this temperature range.

Conformance-polymer systems have been successfully applied for many years to control undesired water production from hydrocarbon wells. However, currently available polymers present a number of limitations for high-temperature wells (>250°F) in terms of providing longer gelation times and acceptable thermal stability. This paper presents the successful field implementation of an organically crosslinked polymer (OCP) for high-temperature applications in southern Mexico. The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneamine (PEI). To date, more than 450 jobs have been performed with the OCP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel pack isolation, fracture shutoff, and/or casing-leak repair. Originally, the OCP system had a limited working temperature range from 100° to 250°F. The upper placement temperature of the system was ~250°F because, above this temperature, pumping times were too short. A recently developed carbonate retarder allows reasonable placement times up to 350°F, without the need for cooling down the formation to obtain enough pumping time. The retarder is not detrimental to the thermal stability of the system. An overview of case histories that used OCP in southern Mexico is presented in this paper. In addition, the development results of the high-temperature conformance polymer are discussed in terms of (1) gelation-time measurement and (2) effectiveness to limit permeability to water and thermal stability in sandpack flow tests at elevated temperatures. To date, more than 70 jobs have been successfully performed worldwide with the OCP at temperatures higher than 250°F. Introduction Excessive water production from hydrocarbon reservoirs is one of the most serious problems in the oil industry. Water cut greatly affects the economic life of producing wells. Unwanted water production is estimated to cost the petroleum industry about ﹩45 billion each year, although accurate records of water production are difficult to obtain (Conformance Technology Manual 1996; Curtice and Dalrymple 2004). The southern region of Mexico presents a major challenge with water management as well. Water production results in extra disposal costs, scale buildup, reduced oil production, and eventually well abandonment (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid excessive water production, even when intervals still retain large volumes of recoverable hydrocarbons. Although natural fractures have a positive effect on oil flow, they also negatively impact water and/or gas flow caused by coning effects or high-permeability streaks between the producing hydrocarbon zone and intervals above and/or below. If these zones contain high mobile-water saturation, they soon will impact the productivity of the hydrocarbon zone. Early water breakthrough caused by edge-water flowing through faults or natural fractures is another common problem in this region. In addition, many of these formations with high-water-management problems produce from intervals with bottomhole temperatures higher than 250°F, hence the need for a high-temperature, porosity-fill sealant in this temperature range.

In acid matrix stimulation, the correct placement of the injected fluids is essential. Several diversion and placement techniques are often applied to obtain the desired fluid placement (Glasbergen and Yeager 2010). Distributed temperature sensing (DTS) and coiled tubing (CT) pressure, temperature, and collar locator tools were used to monitor the fluid placement and effectiveness of the diversion process.Real-time monitoring was required as part of the overall reservoir management strategy for the Tecominoacán 705 well. The CT service provided ideal conveyance for DTS in this highly deviated and depleted well. In a distributed-temperature survey, the fiber optic served as the sensing element, and combined with CT conveyance and pressure/temperature/collar locator tools, enabled continuous wellbore temperature monitoring across the entire horizontal while pumping a stimulation treatment through an annular space consisting of acids and diverters. It also allowed real-time decision making based on the actual measured injection profiles.This well was highly deviated in a carbonate reservoir, completed with 675 m of 4 1/2-in., 12.7 lb/ft liner and swell packers, with 150 m of tubing conveyed perforating (TCP) perforations distributed in six intervals. The DTS combined with CT tools provided accurate monitoring of the stimulation treatment, which was pumped through the annulus between the production tubing and CT. With the DTS service, it was observed that the stimulation fluids were injected only at the heel of the well, which was acting as a thief zone as a result of the presence of highly conductive natural fractures. Several stages of diverters were pumped to attempt to divert acid from the heel to the tip of the well, without success. The decision to cancel the final acid stages saved USD thousands in fluid costs. Mixing the acid on-the-fly using special blending equipment allowed the optimization of resources based on real-time decisions influenced by the DTS injection analysis.

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