Operators developing reservoirs and producing them from deep and ultradeepwater wells are pushing the technical limits regarding horizontal extension. Deepwater wells completed in unconsolidated formations usually have low fracture gradients, severe leakoff zones, and/or significant washouts. Long horizontal open holes, therefore, may become technically difficult or economically unfeasible to gravel-pack with the use of conventional fluids and gravels.Typical completions in offshore Brazil start from a 9 5 =8or 10 3 =4-in. casing, in which a 5 1 =2-in. premium screen and tubular string is hung along an open hole drilled with an 8 1 =2or 9 1 =2-in. bit. Horizontal extensions range from 980 to 4,000 ft. A variety of openhole gravel-pack techniques proved to be complex and costly, but ultralightweight (ULW) proppants have enabled simpler and more-cost-effective gravel packing in these longer horizontal open holes. The reduced gravel density allows a significant reduction in pumping rate that avoids fracturing the formation, minimizes fluid loss, and eliminates the risk of premature screenout caused by excessive gravel settling.ULW-proppant technology was introduced to Brazil in 2005 and has been applied successfully to gravel pack wells under extreme conditions such as low fracture gradient, severe fluid loss, and washed-out zones. ProppantULW-1.25 has proved to be effective for packing wells with narrow sections through the openhole interval, frequently found in horizontal wells completed through shale zones that are isolated by reactive packers and/or mechanical external casing packers. ULW-1.75 was introduced in Brazil in 2007 and has largely replaced ULW-1.25 for gravel packing wells in which an improvement in the operational pumping window is required. A combined package comprising ULW-1.75 during the alpha-wave phase and ULW-1.25 during the beta-wave phase is also discussed. This paper summarizes the procedures and results of almost 60 wells that have been gravel packed with the use of ULW-proppant technology pumped for a local operator.

Can unconsolidated sands, with no intergranular cohesion forces, really be hydraulically fractured? Does conventional hydraulic fracturing theory adequately explain treatment behavior and production results? If the unconsolidated formation is considered to be a fluidized sand bed, is the classical linear-elastic two-wing hydraulic frac assumption still valid? Alternative proppant stimulation mechanisms may better describe the process, including squeezing or forcing by viscous fingering of the high-permeability proppant slurry into the formation. In this scenario, traditional fracturing design parameters such as pad volume, pump rate, proppant concentration and especially fluid viscosity will have new and significantly different effects on the treatment outcome. This paper explores these concepts and shows how they can explain both treating behavior and production responses of so-called "frac jobs" or "sand-oil-squeezes". Alternative treatment and fluid design criteria are proposed to achieve more consistent and predictable production responses, based on field performance. Fracture propagation? The stimulation process in unconsolidated sands is not yet fully understood. What is evident is that conventional linear elastic fracture mechanics (LEFM) are not applicable and conventional models often do not adequately predict the treatment behavior. The theory of hydraulic fracturing is based on LEFM that apply to cohesive rock formations. In conventional hydraulic fracture simulations, initiation and propagation is governed by insitu stresses, mechanical and poro-elastic properties, and "fracture tip effects", such as fracture toughness, the nonwetted zone (fluid lag), tip dilatancy, and the process zone.1 Unlike competent formations, unconsolidated sand beds have little or no tensile strength or grain-to-grain cohesion, and could be defined as a high viscosity sand slurry under confinement pressure. Accordingly, the aforementioned fracture tip effects are not present in these formations. For example, the non-wetted zone does not exist, as Khodaverdian and McElfresh observed with 200-mesh sand packs in radial flow cell experiments. The measured pore pressure in the vicinity ahead of the advancing "tip" actually increased due to filtrate invasion prior to parting. A strong dependence on fluid efficiency was reported, with high leakoff fluids generating multiple, sub-parallel "fractures" (or plastic shear failure zones), and low leakoff fluids generating single, more continuous, failure zones.2 In experiments fracturing gelatin molds, Stockhausen, et. al., identified a strong correlation between fluid inertia (and hence pump rate) and fracture orientation in isotropic stress environments. Low injection rates resulted in fractures tangential to the wellbore, high rates produced radial fractures, and intermediate rates resulted in T-shaped (radial and trangential) fractures.3 In Western Canada, cold heavy oil production is routinely employed without sand exclusion techniques, resulting in massive sand production due to plastic flow of the granular, heavy oil-saturated matrix. Geilikman, et.al., developed a continuum model that treats the sand bed as viscoplastic skeleton saturated by a viscous fluid. In this model, after surpassing the yield stress, the fluid-saturated, granular, formation fabric will flow as a dense suspension, governed by its viscoplastic rheology.4 Combined stimulation/ sand control treatments, called Sand Oil Squeezes (SOS), have been employed in Venezuela and other areas for four decades.5,6,7 These treatments, which consist of an injection of a slurry of high concentrations of gravel in viscous oil into the formation prior to a gravel pack, were originally considered to be squeezes, not necessarily fracture treatments. With the advent of the frac pack technique in the early 90's, the theory behind the SOS was reworked to conform to the fracturing process. The authors contend that the original squeeze theory may more closely represent the injection process in unconsolidated sands than the frac pack theory. Note that it is commonly observed that the injected SOS slurry volume often exceeds the estimated void space behind the casing.

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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Cupiagua retrograde Gas-Condensate reservoir, in the Llanos foothills of Colombia, was developed using a fast-track approach to provide production against an aggressive delivery plan. Unfortunately, an unusually severe condensate-banking effect combined with difficult perforating and drilling induced damage, meant that deliverability of the wells failed to achieve the desired levels.This paper describes the approach that was taken to economically remediate these multiple-stacked reservoirs by the novel deployment of a through-tubing Frac-String. In addition, due to the highly tectonic regional-stresses, the final variant of this through-tubing frac-string was designed to permit surface treating pressures of up to 18,500 psi.This solution was primarily possible due to the mono-bore completions with which the Cupiagua field had been originally developed. The frac-string was deployed through tubing with open perforations on the annulus; in addition variants, such as a slim-hole frac-string, allowed deeper zones within smaller production-liners to also be stimulated. The technology of the Frac-strings was incrementally developed over time and in this way new and more increasingly complex challenges could be undertaken without dramatically increasing the overall risk on each treatment.More than 136 deployments of various string variants have been performed successfully; and even though annular tool clearances have been as low as 1/20" there has not been a single stuck-pipe incident to date. Throughout these operations the frac-string pressure test history has been faultless and the cumulative proppant placed during the frac treatments has amounted to more than 6,250,000 lbs.Finally, significant production increments have also been achieved, the first well increased in productivity from ca. 8,000 bcpd to 18,000 bcpd and numerous low delivery wells were stimulated into becoming major producers. Individual case studies will be presented to support this, along with the production histories of the first 3 treatments.Remedial treatments, of these deep tectonic wells, have been economically feasible due to the ability to deploy a fracstring through the existing completions. Variations on the actual rig-up, deployment and design have allowed economically less favourable wells to become feasible candidates. In addition, the continued field development, extension and infill drilling has also been made possible by the application of this novel approach.