Reservoirs comprised of poorly consolidated sands are generally prone to some level of sand production throughout the life of the well. This sand production creates many challenging problems for the operator such as erosion and/or failure of both down-hole and surface equipment, lower well production due to tubular fill-up and, finally, environmental issues related to the final disposition of the produced solids. All of these problems also have a common denominator: they significantly increase the cost of production for the well's in question.Conventionally, the application of any technique for controlling sand production is recommended as soon as it is known that the problem exists. Among some of the solutions available are 1) sand control by mechanical means using slotted liners and screens combined with conventional gravel packs, 2) prepacked completion screens, 3) lowering the production of the well thereby reducing the draw-down across the formation and 4) chemical sand consolidation (CSC) resin treatments: the latter being the focus of this paper.The principle behind the CSC process is the adherence of sand grains to a liquid resin that, while cross-linking occurs, penetrates and hardens across the porous matrix. The newly create mass of consolidated sand exhibits much higher mechanical strength, able to withstand the drag forces generated by oil production.CSC resins can be injected either when a well is initially completed or during workover operations which are needed to clean a sanded-up well-bore where said sand deposition is the result of failed completion screens or slotted tubulars. In such cases, the CSC resin acts as a plug across the heightened sand producing area and represents an economically viable alternative to complete replacement of the damaged tubulars or, as a worse-case scenario, well replacement. This paper will discuss a combination of technologies where both CCTWV (used to clean the well and detect the sand intrusion points) along with CSC resin technologies were used to successfully repair two wells in the unconsolidated URD-01 reservoir that were producing sand through holes in 5" Slotted Liner and 3-½". pre-packed completion screens.

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World demand for energy is substantial and continues to grow. By 2020, it is expected that the world will need approximately 40% more energy than today, for a total of 300 million barrels of oil-equivalent energy every day. Meeting higher energy demands will require a portfolio of energy-generation options including but not limited to oil, natural gas, coal, nuclear, steam, hydro, biomass, solar and wind. New horizons are being explored. Wells are drilled in greater water depths. Drilling units are continually upgraded to target deeper hydrocarbon-bearing zones. Wellbore tubular metallurgy is continually upgraded. Drilling, completion and stimulation fluids are being developed for extreme temperature and pressure environments. As the preferred technology to enhance "oilfield" energy production, well stimulation has and will continue to have an important role in fulfilling the world's future energy needs. Well stimulation generally uses fluids to create or enlarge formation flow channels, thereby overcoming low permeability, as in "tight" formations, and formation damage, which can occur in any formation type. A common and very successful stimulation option, matrix acidizing, utilizes acids that react to remove mineral phases restricting flow. Depending on the formation and acid type, flow is increased by removing pore-plugging material; or by creating new or enlarged flow paths through the natural pore system of the rock. However, higher-temperature environments present a challenge to matrix acidizing effectiveness. High temperatures can negatively affect stimulation fluid properties and certain acid reactions. Thus, careful fluid choice and treatment designs are critical to successful high-temperature matrix acidizing. With proper fluid selection, design, and execution, matrix acidizing can be applied successfully to stimulate high-temperature oil & gas wells and geothermal wells. These types of wells have some common features, but they also have significant differences (e.g., completions, mineralogy, formation fluids and formation flow) that influence stimulation designs and fluid choices. This paper summarizes best practices for designing matrix acidizing treatments and choosing stimulation fluids for high-temperature oil & gas wells and geothermal wells. Included are case histories from Central America. Lessons learned about differences and commonalities between stimulation practices in these well types are also discussed. Introduction As today's rate of finding new reserves is lower than in previous decades, exploration has turned more to deeper basins. Deeper wells are typically hot (greater than 250º F, for example). Permeabilities are also often lower and occasionally are the result of a network of natural fissures. Offshore wells in the Gulf of Mexico are now reported to reach bottomhole temperatures of 500º F. Recently discovered gas fields offshore Brazil have bottomhole temperatures ranging from 350 to 400º F. Over the past years, great improvements in matrix acidizing have taken place, parallelling the developments in hydraulic fracturing. Provided that the forecasted production/injection results make economic sense, matrix acidizing is still simpler, often less risky, and more economic to implement than hydraulic fracturing. Sophisticated laboratory equipment, expertise, and well testing software can help the engineer diagnose production or injection damage effects and mechanisms - making it easier to select proper well candidates and optimize job design. Treatment placement is better ensured through the use of chemical or mechanical diversion methods and technologies, and placement tools (coiled tubing, straddle packers, etc.). On-site quality control is enabled by modern sensors, monitors and software, enabling the engineer to determine the evolution of skin with time, and radius of formation treated. Modern blending and pumping equipment have provided the means to mix acid continuously without the need for pre-blending fluids. This eliminates the need for mixing tanks on location, and enhancing safety on location 10.

Unconventional energy sources have become one of the keys to keep the world energy supply along with a sustainable development. In Central America, geothermal power is one of the most important energy sources, given the limited fossil fuel reserves in the area. The region imports 75% of its energy requirements, and geothermal-generated electricity in many countries represents 10 - 25% of the national supply. In fact, Central America is one of the world's richest regions in geothermal resources, according the world energy council. Despite that the region has an estimated potential for geothermal electricity generation of 4,000 MW, the actual installed capacity is only 508 MW (CIA world fact book). Most of the geothermal projects in Central America produce below their potential due to two main factors: depletion and low productivity (or injectivity) due to scaling in tubulars and formation damage. The damage is typically due to several causes, including drilling mud damage, production fines migration, silica plugging and scales in the reservoir. This paper describes the results of a five-year well stimulation campaign in El Salvador and Nicaragua, in several geothermal fields, run by different operators. More than 20 stimulation treatments were performed using different acid systems in volcanic and metamorphic rocks. The laboratory observations, their analyses and corroboration with the field data show that the combination of a properly designed treatment and special acid blends has lead to significant improvements in the stimulation of such reservoirs. Comparison of results in different reservoirs with varying stimulation treatments is also included as reference. Introduction Geothermal power consists in sourcing energy from earth's heat. This heat comes ultimately from the earth's core (estimated temperature 4,400 to 6,100°C), which heats the earth's mantle, as shown in the figure 1. In locations where magma from the mantle is closer to the surface (e.g. in volcanoes, mid ocean ridges, hotspots, etc.), an abnormally high temperature gradient is observed. Geothermal reservoirs are usually found in such high geothermal gradient locations. Subsurface water is heated by hot rock in these locations. If this water is able to flow (e.g. the subsurface rock is permeable or fissured), then a well can be drilled to enable this hot water to be produced to surface, as represented in the figure 2. Then, if the water is hot enough, steam from it is able to drive an electric power generator (Aboud). A very common example of such hot subsurface water locations are geysers. History of geothermal power generation started using steam directly from such geysers. With time, in order to increase the steam flow rate and the steam temperature, geothermal wells were drilled. Today, several geothermal fields are located in areas where no natural surface steam flow (e.g. geysers) is present.