The results of stimulation treatments in southern Mexico's carbonate reservoirs have been significantly improved using a new fiber-assisted, self-diverting acid system. These reservoirs are thick, deep, and hot. Depths are usually greater than 15,000 feet, bottomhole temperatures reach up to 350°F, and permeabilities range from 1 to 1000 mD within the same interval. Wells are typically completed with multiple perforated intervals. In the past, high-viscosity diverting fluids have been used to improve zonal coverage during stimulation treatments. Despite repeated treatments during the life of the well, in many cases, post-treatment logs show that the treatment was not effectively diverted to lower permeability, less productive intervals. To overcome these challenges, we introduced an innovative degradable diverting acid system combining the properties of viscoelastic diverting acid (solid-free) and degradable fibers to southern Mexico. This, combined with a rigorous candidate selection process, resulted in improved zonal coverage, increased oil production, and higher ultimate reserve recovery. Maximizing oil production using this diverter system requires a detailed understanding of the petrophysical properties of the reservoir and production history. This information helps determine treatment volumes and the volume and number of diverter stages. Wells with the highest permeability contrast are often the best candidates. In many cases, producing from natural fractures depends on correctly determining the number and volume of the diverter stages. The experienced gained from treating more than 10 wells has resulted in the development of clear guidelines with respect to the treating fluid, volume, and number of diverter stages. On average, the guidelines have resulted production increases of 1,500 BOPD. By applying the treatment guidelines with an effective diverter fluid, operators can significantly increase oil and gas production in previously stimulated or new wells within naturally fractured carbonate reservoirs.

Carbonate reservoirs in the southern region of Mexico are characterized as deep, hot, and naturally fractured. Most wells in Cretaceous and Jurassic carbonate formations are acid stimulated at the time of completion and periodically during the life of the well to combat damage mechanisms that occur during drilling and production. These wells are typically completed with multiple perforated intervals. Not all the intervals have the same density of natural fractures, some sections having no natural fractures. This creates a very high permeability contrast estimated to be as high as 1000:1 in extreme cases. Also, the reservoir pressure varies between the different intervals as a result of simultaneous production from zones with widely varying permeability. The contrasting permeability and reservoir pressure constitute a major challenge at the time of stimulation treatments in terms of achieving uniform zonal coverage and fluid penetration in all treated zones. The treatments are bullheaded, so effective diverting fluids are required to ensure the complete vertical coverage of the zones of interest. The diversion, however, must be temporary and nondamaging to the reservoir and the natural fracture network. To meet this challenge, a degradable acid-diversion system has recently been applied in matrix acidizing treatments in southern Mexico. The diversion system combines the viscosity-based effect of self-diverting acid with particulate-based diversion provided by degradable fibrous material. The combination functions synergistically to provide superior zonal coverage of matrix treatments under extreme conditions. In acid fracturing applications, the new system reduces leakoff in fissures and natural fractures, which leads to a more efficient spending of the acid and therefore longer fractures. The degradable nature of the fibers and viscoelastic surfactant result in no post-treatment damage. Furthermore, the fibers produce a weak acid while dissolving in the presence of water at bottomhole temperature, continuing to stimulate the well as they degrade. This paper presents three case studies in which superior results were obtained by using the new diverter when compared to results achieved in offset wells in the same reservoirs and under similar conditions conventionally stimulated. Production increases in excess of 100% have been achieved where conventional treatments have failed to increase production. Lower production decline and higher flowing pressure have also been observed. The latter is interpreted to be the result of the fluid diverting from highly fractured and depleted zones into undrained lower-permeability with fewer natural fractures.

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.

This work describes the experience in the use of Bronze-Aluminum coated sucker rods at Chihuidos de la Sierra Negra and Lomitas fields, operated by REPSOL-YPF (Rincón de los Sauces - Neuquén). This new material was developed specifically to work in the corrosive environment of the oil producing wells of those fields. This development was a result of a team work, manufacturer and user. Its objective was to find an acceptable solution (technical and economics) for the sucker rods used at these fields. Introduction Chihuidos de la Sierra Negra and Lomitas fields are located at in Neuquén province, Argentina. Those fields started their development since the end of 80's. Producing formations are Troncoso and Avilés (1000–1100 and 1300–1500 m. deep) with 5.5 OD casing and 2 7/8" OD production tubing. Starting 1997 those fields had 652 producing wells (Gross production rate of 40000 m3/d, 20000 m3/d of oil production rate). In 1993 started the secondary recovery program (selective water injection). This program started by injection of 500 m3/d, today the rate of injection is about 82000 m3/d. As a result of that, water cut has growth from 10% to 50–70%. GOR of the wells are 10/20, with a 60% of CO2 in the gas. Initially those fields were lifted by sucker rod pumping, using API 86 or API 76 rod strings. As those fields were responding to the secondary recovery program, dynamics levels were growing constantly. So the operating company decided to adequate the lifting systems:Electric submersible pumps were installed (high production rate wells)Re-desing of beam pumping installations First stage involved the use of high strength sucker rods (3–4 wells). Due to the severity of corrosive environment (not recommended for high strength rods) and the problems with the corrosion inhibitors, those rods were pulled out from these wells. The operating company decide to start a program of corrosion inhibition, in this way they increase the performance of sucker rods. Despite of that, certain conditions as wearing, high velocity flow rates, high fatigue loads result in a necessity of a new material for certain wells. In these wells Grade D rods were not applicable, in fact there were wells in which rods had a service life less than 60 days. Development 1 - Wells characteristics Typical installation of beam pumping wellsDepth: 1.400/1.800 mTubing: 27/8"Pump bore size: 2.75"Pumping Unit:: C-912–365–192Stroke: 168"-192"Pumping speed: 8/10 spmProduction Rate: 100/200 m3/day (50/70% Water cut - GOR 10/20)String type (before coated rods): API 87 1–2 Corrosive environment1–2–1 Chemical data from water (producing wells)Density (gr/lt) 1,0 - 1,10Temperature (°C) 40/50pH (well head measurement) 6,00/6,50

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