The Guando field in Colombia, South America, is a sandstone reservoir with an initial pressure about 150 psi at GOC. A waterflood has been implemented since early in the life of the field. A complete set of data has been maintained on each of the injectors since 2002. This data set includes: daily injection rates, pressures, water quality and solids analysis. Injection into four different hydraulically fractured reservoir units is controlled by down-hole valves. In some cases wells are operated at injection pressures above the fracture gradient. To ensure good reservoir sweep efficiency, waterflood control and assurance of injectivity for each reservoir unit a detailed study of the injectivity of each injector was undertaken to understand the possible growth of fractures and its impact on frac-pack injectivity, injection profile and oil recovery. Field data indicates that the quality of river and produced water streams, mechanical configuration, stimulation of injector wells and injection facilities are important parameters that control the injectivity behavior. Injection well simulations are presented to show that the injectivity behavior can be history matched quite well and this process provides valuable insight into the dependence of injection parameters such as injection rate and water quality on injection profiles and fracture growth. This paper presents data and history match simulations for seven injectors from the field. The results allow us to estimate the fracture lengths that are created in the injectors and to thereby evaluate the effectiveness of injection schemes being implemented. This history match study allowed us to make recommendations for future injection rates and water quality into each of the injectors. To the best of our knowledge this is the first time that the injectivity of multi-layered, frac-packed injectors has been history matched with field data over an extended period of time. These history matched results validate our injection well model for frac-packed injectors and provide important guidance on future injection well design in addition to making concrete recommendations for the Guando field.

The Guando field is a late Cretaceous sandstone with two distinct reservoirs with total gross thickness of approximately 1300 feet. Discovered in 2000, the field is Colombia's largest oil discovery since the mid 1980's. Due to the low initial reservoir pressure, water injection began almost simultaneously with field development. Water is injected selectively into the main reservoir's main sands in order to optimize the distribution of injected water. However, oil recovery efficiency is challenged by reservoir heterogeneity, including natural fractures. The first polymer gel conformance application in Colombia was implemented in 2008 in an effort to improve waterflood sweep efficiency. The objective of the gel treatments was to reduce the permeability in the most conductive natural fractures of the lower layer, ARIN formation. The conformance pilot included two non-adjacent patterns. Initially, the design team considered isolating the upper reservoirs and treating only the lower reservoirs. The treatment designs included several stages of varying gel concentrations and injection rates, which were modified in the course of each treatment application based on surface pressure response. Post treatment oil response occurred within approximately two months and payout was achieved in less than ten months, driving new candidate selection and treatment in 2013. The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as the most effective solution to severe water channeling. Also, we will present plans for additional gel treatments with an emphasis on cost reduction and improved treatment designs. Polymer gels have been successfully applied in naturally fractured reservoirs for almost two decades, however, reservoir characterization tools continue to evolve, providing more precise diagnostics that offer improved conformance treatment designs. This case history will provide an updated framework for operators considering chemical sweep improvement technologies as part of an integrated field management strategy.

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SPE paper 94569 (2005) presented the generalities, characterization and initial development plan of the Guando field, an extremely underpressured, sandstone, partially naturally fractured reservoir. This paper will present global results of the initial development program and the bases which guided to implement a reduced spacing project based on decreasing wells distance from 250 to 145 meters. Results of this new development stage are presented and discussed. This project increased field reserves in 15% and accelerated the production, allowing a 15% recovery factor in just seven years since the field exploitation started and nine years from its discovery and only with a total injected water of 0.25 volumes of its original oil in place. Introduction This field located in Colombia, South America (Fig. 1), was discovered in year 2000 by Petrobras (Operator) and its partners Ecopetrol and Nexen. Due to its extremely low initial reservoir pressure, initial field development program was based on waterflooding the reservoir since the beginning, on an inverted seven spot pattern, with a well spacing of 250 meters, complemented with peripheral injection and having as a principal component the selective injection to compensate the reservoir heterogeneity and then improve the vertical sweep efficiency. The implementation of this development program showed better results than expected, which was a motivation to plan and implement a reduced spacing pilot on the same inverted seven spot configuration, but now, with wells located at 145 m. The implementation of this phase was made in several steps:an initial pilot with three producer wells;an extended pilot with 15 new producers;drilling of 40 additional wells and;conversion of 11 producers to injectors and injection increase in 30,000 bwpd, rising the total water injection rate to 105,000 bwpd. Selected strategy and the accelerated way on which it was implemented have allowed getting a 15% recovery factor in nine years from field discovery. Review of reservoir characteristics This reservoir is a late Cretaceous (Guadalupe group), formed by fine to coarse grain sandstones, which are highly bioturated and correspond to a shallow marine to transitional depositional environment, with an average thickness of 700 ft on the main reservoir. Natural fractures exist in the majority of the field having an important effect mainly since the injection point of view, by its negative impact on sweep efficiency; fracture characterization models indicate connectivity of the system is not good for the most of the reservoir, with the exception of some areas locate close to faults (Fig. 2). Since the structural point of view, this accumulation corresponds to a sub thrust structure decapitated by Boqueron fault and with some inner faults which form indepndent reservoir blocks (Fig. 3). The reservoir is located at an average depth around 3500 ft, with the whole reservoir above the sea level. This condition combined with a thought hydrodynamic effect brings one of the more important Guando reservoir characteristic, which is its extremely low reservoir pressure that at the depth of the gas-oil contact (GOC) is only 100 psi (@1810 ft above sea level), having a maximum around 500 psi at the oil-water contact (OWC) depth.

Water injection performance depends on the petrophysical reservoir properties and fluid-flow characteristics. Reservoir simulation models should include rock properties variation and rock-fluid interactions and, when it is necessary, geomechanical phenomena. When water Injection above Fracture Propagation Pressure (IFPP) is used, its effects over the reservoir model performance, and specially, on waterflooding sweep efficiency, become a critical point to be assessed. Quantification of these effects using parameters such as the Recovery Factor (FR) and Net Present Value (NPV) is important for the water injection project dimensioning and to determine the feasibility and usefulness of the injection process to be implemented. Water injection under fracturing conditions is an important method to overcome the production decline caused by the injectivity loss in reservoirs with water injection. Also, the modeling of injectivity loss and fracturing processes are subject of several studies, which aim to understand these processes in order to enhance the results to be used for the reservoir development strategy proposal. The objective of this work is to quantify, using Sweep Efficiency and NPV as study parameters, the effects of anisotropies on the production performance during a waterflooding under fracturing conditions. The methodology proposed considers the simulation of scenarios in which the injectivity loss is represented by an analytical decline model, and the fracture is represented using a virtual horizontal well. This proposal is implemented in order to show the effect of the water injection - injectivity loss - fracturing process on the reservoir behavior. Three different fluid models were used to illustrate their effect in some production parameters and usefulness of fracturing process in several scenarios. The results show the applicability of water injection under fracturing conditions in different scenarios. In addition, this work shows the importance of the reservoir parameters into the injectivity loss and fracture propagation models, the significance of the FR and NPV in the quantification of these effects. Finally, the relation between the heterogeneity degree and production parameters is presented. Introduction Water injection is the most common method for oil recovery and pressure maintenance. Injectivity loss is the principal problem associated with water injection. Altoé et. al.1 describe that it is caused, mainly, when seawater, produced water or any other poor quality water is injected into reservoir. Solid and liquid dispersed particles from the injection water are deposited in the porous media; it can turn inefficient the injection process with time. Palson et. al.2 comments about different solutions that can be applied to improve the injection process:treatment of the water injection for removal suspended particles, bacteria and oil droplets,well workovers for removal the damage, using mechanical and chemical treatments. As mentioned by Souza et. al.3, any of these solutions can be expensive, some in CAPEX, others in OPEX. Actually, there is other option to attack the injectivity decline and it is know as water injection above the formation parting pressure. This option reestablishes the well injectivity creating high conductivity channels and avoids complex systems of water treatment. However, the apprehension to use water injection above formation parting pressure is associated to the canalization of the injected water towards producing wells leading to negative results for the production performance. Even though, this technique is applied in North Sea and Alaska (Ovens et. al.4, Ali et. al.5). Due to complexity and number of variables, involve in water injection above formation parting pressure, recent studies are focused in different aspects as fracture mechanisms, modeling and fracture's effects in the reservoir performance (Van den Hoek 6, Gadde et. al.7). To model those effects, the fracture behavior must be reproduced in the flow simulator and its effects in the behavior of the production during the process of injection of water. It also necessary study tools that allows model the injectivity loss. In this way, it can couple the process injection with injectivity loss and fracturing in a more complete and coherent way for refined and coarse simulation grids.