Gigante-1A (G-1A) is a well that is located in Upper Magdalena Valley in Colombia, South America. It has been producing for almost 10 years today. There are several wells in this area that have been producing from sandstone and carbonate/dolomite reservoirs at different depths for more than 30 years and are still drawing interest from producers. There is a high interest in new well construction based on experiences from G-1A related to drilling, completion, production stages, reservoir analysis with stimulation techniques, and response-related identification of formation damage. A second well at the same depth is currently in progress. The specific condition of water, oil, and gas flowing commingled to surface from the same zone, covering sandstone and carbonate formations with significant petro-physical differences and reservoir fluids has allowed for the establishment of best practices and identified areas of research to get improved responses. A continuous learning curve focused on improving operational procedures and placement techniques has been built according to the mechanical status of the well before each intervention. Periodical interventions focused on organic deposition, emulsion blockage damages, and scaling related problems have helped to establish operational and treatment design procedures which contribute to effective stimulation results. Continuous improvements related to chemical treatment designs, based on adjustments of formulations, radius of penetration, and placement techniques, have helped to ensure effectiveness. Chemical treatments have focused on organic, nature-related problems since the beginning. In particular, asphaltenes flocculation, have generated pore throat blockage because of asphaltenes deposition and emulsion blockage. Water cut increase over time has brought inorganic scaling problems. Corresponding solutions have been combined with organic stimulation treatments for removal and damage inhibition overtime. There is also a clear learning curve over the last seven years on well lifting in optimizing well production in conjunction with chemical treatments to maximize oil production. Introduction G-1A is geographically located southern department of Huila, about 26 kilometers southeast of the municipality of Gigante. This HPHT well produces from Tetuan formation, where it was completed in May 1998 for the perforated interval 15,372 to 15,430 ft, in 5-in. Liner N-80, 18#/ft, hung at 14,956 ft. 7-in. casing P-110 29#/ft, from surface to casing shoe at 15,349 ft. The target zone in G-1A well in particular combines sandstone and limestone interval lengths along the perforated interval, where the bottomhole reservoir temperature has been identified as 268.5° F. A summary of current downhole conditions according to the most recent production report has been compiled in terms of well characterization related to main reservoir properties, formation fluid data, and current artificial lifting system (Table 1). G-1A has been periodically stimulated for almost eight years after confirming oil reserves through openhole log analysis, reservoir studies, hydraulic fracturing responses previous a blowout in 2000, PBU indications, and nodal analysis after blowout. Formation damage has been considered since the beginning of stimulation treatments after blowout. The blowout was a critical event during well history since a significant impact was made on the mechanical configuration at downhole conditions. Consequently, water reservoir communication has been highly estimated.
Approximately 30 relative permeability modifier (RPM) fracturing treatments performed in Colombia will help establish consistent, reliable best practices for future applications. Some of these treatments combined scaling inhibition stages to maintain production enhancement, in spite of high or medium formation water scaling tendencies. Because the water-injection system is significantly dynamic in these fields, new injection water channels were communicated with producer wells after RPM-fracturing treatments, reducing scaling inhibition requirements and RPM effectiveness for water production management. The objective of combining RPM and fracturing treatments was to increase oil production over time through effective water production control techniques. Evaluations of the effectiveness of both general and specific treatment processes and service are available in the industry. However, data for the analysis of RPM-fracturing treatments presented in this paper was obtained in two basic procedures:The workover operating efficiency (WOE) index was established to evaluate fracturing effectiveness (total fluid production increase) and RPM effectiveness (water-oil ratio [WOR] reduction). The WOE index quickly analyzes all treatments and identifies the best-performing ones based on two factors:production-related WOE indexes higher than one, which is the maximum production rate after treatment vs. the minimum production rate before treatment, andWOR-related indexes lower than one, or the minimum WOR after treatment vs. the maximum WOR before treatment.This analysis can quickly define the best and worst performances by evaluating individual fracturing effectiveness and individual RPM effectiveness.The reservoir-performance analysis is a cyclical and detailed process that does not focus on individual wells but rather analyzes the entire reservoir. This stage consists of an extensive analysis that involves reservoir characterization, well testing and production history, completion design, stimulation operation design, and stimulation operation execution and feedback. Because this analysis was so extensive, it was applied only to the best- and worst-case scenarios (two different fields) in which combined RPM-fracturing/scaling inhibition treatments had been in effect for more than 2 years. Those two fields presented some similarities in terms of producing-zone depth, reservoir character, reservoir fluid properties, and water-injection systems. Both general and specific processes for treating and servicing wells have been evaluated for effectiveness by the industry. Applying the results of the two analyses presented in this paper, best practices are now defined for future well selection, treatment design, and operation execution for combined RPM-fracturing/scaling inhibition treatments. Introduction An average of 15 RPM-fracturing treatments for each of two fields was evaluated for this study. These fields, identified as Fields A and B, exhibit many similarities and only a few differences. Both are sandstone, producing formations with typical average clay minerals content. Producing zones are average with similar depths and bottomhole temperatures. The collection, review, and analysis of these jobs has been sufficient for defining best practices for future jobs on similar wells. A detailed analysis of the entire reservoir and field was performed for two scenarios: the best and the worst case. These cases were defined according to:the highest production increase ratio as a moving average during 3 months,the highest incremental production after 6 months, andthe lowest water-oil ratio decrease as a moving average during 3 months.1 Additional details and concepts for the two basic analysis procedures based on well performance are provided in the following sections.
One of the major challenges of stimulating wells in the San Francisco and Balcon fields in Colombia is adequate fluid placement. The wells in these areas have different zones open to production. Typically, these zones show severe petrophysical contrasts regarding permeability, porosity, and oil-and-water saturations. Permeability can be 25 times greater in one zone than another. Furthermore, these open zones may also have different pressures. These variations in rock and fluid properties increase the probabilities for preferential flow to the zones of less resistance. Therefore, selective stimulation techniques are commonly used to treat wells in these two fields. Single and straddle packers for bull-heading and coiled tubing with conventional nozzles are some of the commonly used techniques. This paper discusses the results from using CT and a fluidic oscillator as a new alternative to place stimulation fluids. A true fluidic oscillator generates pressure waves using the Coanda effect. These low amplitude, high-frequency pressure waves enhance damage removal and fluid placement through cyclic loading. This technique has been extensively used in the San Francisco and Balcon fields for Hocol in Colombia. Three stimulations using CT and a fluidic oscillator are discussed in this paper as well as the results from this fluid placement technique with conventional placements showing how the use of CT and a fluidic oscillator can increase hydrocarbon recovery. Introduction The San Francisco and Balcon Fields both produce from the Caballos formation (Cretacic). These two fields are located in the Neiva sub-basin in the upper Magdalena Valley, from 15 to 30 miles northwest from Neiva, Colombia. Fig. 1 shows a map of the area and Fig. 2 shows a typical log and a stratigraphic column. The Balcon, which was discovered in 1988, and San Francisco, which was discovered in 1985 are mature fields. Both fields have a broad range of petrophysical property values. Permeability varies from 200 to 2,000 mD and porosity from 9 to 18% as shown in Table 1. The primary drive mechanism for these reservoirs is solution-gas-drive. Wells in these fields are typically stimulated by bull heading or by running a straddle packer system when the well is worked over. They are also stimulated using CT with conventional jet nozzles. A novel and beneficial approach was taken to use a fluidic oscillator at the end of the CT. San Francisco Field The San Francisco Field is located in the Neiva sub-basin, in the Upper Magdalena Valley. It was discovered in 1985 when the SF-001 exploratory well was drilled. Three additional wells (SF-002, SF-003 and SF-006) where drilled in the first half of that year to confirm the reservoir. An additional 28 wells were drilled during the second half of 1985. It is currently part of the Palermo contract between HOCOL and ECOPETROL. San Francisco's main reservoir is the "Caballos" formation (KB). This formation has been divided into 12 flow units: 9 on the Upper Caballos formation (UKB) with a total of 77% of the original oil in place (OOIP). The other three flow units are in the Lower Caballos formation (LKB) with 23% of the OOIP.
Description This paper discusses well-interventions in Colombia that use a new generation of polymeric selective-water-reduction (SWR) product for selected candidates, treatment definition, differences of composition, radius of penetration, stages according to formation petro-physical properties, and well-productivity response in the short and long term. The evolution and improvements in technology over the past five years and its application in Colombia will also be discussed. Previous papers have presented databases with information from interventions around the world, including case histories from Colombia (Dalrymple et al. 2007). This paper will focus on more detailed information for selection, treatment, and operational procedures in Colombian fields. Application There are hydrocarbon-producing formations in Colombia that have productivity limitations because of their high relative-permeability to water. This condition has generated increased tendencies to water-coning, historical and gradual water cut increases, and promoted a negative impact during the productive well life. This technological application includes new perforated wells (which are characterized for a potential rapid water-coning based on the geographical area or the formation) or producing wells in mature fields where the intervention still presents economical benefits. Information will be presented from wells with zones covering mid-to-high permeability, clean sandstones, and argillaceous sandstones at temperatures ranging from 125 to 250°F. Results, Observations, and Conclusions There are records of successful treatments, allowing for a reduction in the water to oil ratio, with increased productivity which has been maintained for more than three years. It has been possible to identify benefits from the technology, its evolution, and improvements during recent years. However, candidate-selection criteria have been continuously adjusted, which has generated more successful cases. Significance of Subject Matter Selective water reduction (SWR) is a viable technology with an extensive history of applications worldwide, and its usage has increased during the last five years in the productive basins of Colombia. A strong, continuous improvement effort has been in place for better reservoir characterization, understanding of water-production mechanisms, laboratory protocols, candidate selection, treatment design (volume estimation, placement techniques), and treatment follow-up. Introduction The SWR treatment is a confirmed technical, operational, and economical water-management option because it can be bullheaded into open intervals without isolation of water zones from hydrocarbon zones. The productive lives of many wells have been extended, which has resulted in high potential-profitability value for mature fields with high water cut.
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