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La Cira Infantas (LCI) is the oldest oilfield in Colombia, with 100 years of oil production history spanning three periods: primary depletion, the first waterflood (WF) period, and the second WF period. After the first WF period, the field had neared its economic limit and an abandonment program was underway from 2003 to 2005. Partners Ecopetrol and Occidental made the decision to implement a waterflood redevelopment project in 2005 that included reconfiguration of the old WF areas and WF expansion into new areas. The partners formed integrated reservoir development and management teams (RDT and RMT) that have combined workovers, infill drilling, WF optimization, and other IOR/EOR methods. The oil production has increased from approximately 5,000 to over 43,000 bopd, which is above the predicted 40,000 bopd. One of the key components was WF conformance controls to improve sweep efficiency and to improve injection profiles across multiple stacked-sand layers. The selective injection method was implemented using multiple packers and side-pocket mandrels/valves. The design of selective injection strings involved complex engineering calculations and left some room for improvement. This paper describes a new workflow used to optimize the selective injection design using multiphase flow simulation based on actual WF patterns. A field pilot test used an inverted 5-spot WF pattern to demonstrate this new workflow. The simulation results predicted a 45% incremental oil production above the base case. The simulation optimization process reduced the number of mandrels/valves from nine to six, which saves about 30% of the associated completion costs compared with the initial completion proposal for this case study.

The La Cira-Infantas (LCI) oilfield was discovered and put in production in 1918. After a traditional reservoir depletion stage, a water flood (WF) operation was started in 1958. Redevelopment began in 2005 as a joint venture between Ecopetrol and Occidental (Oxy) using a combination of workovers, infill drilling, WF optimization, and other IOR/EOR methods. The field has been redeveloped using an average 20 to 25 acres per WF pattern, which were either inverted 5-spot or 7-spot configurations. Since 2005, selective completion strings were installed with side pocket mandrels controlling the vertical distribution and volume of water injected with each mandrel covering a group of sand layers. The selective completion was successfully implemented, and provided a significant boost in oil production. The field has multiple opportunities to increase oil production. Before performing these solutions, it was important to understand the producer-injector connectivity across the entire field. The capacitance resistance model (CRM) provided some insights on the interwell connectivity within the reservoir between injectors and producers, however it is difficult to correlate the CRM simulation results with multiple geological interpretations and reservoir characterizations using geostatistics. This paper presents a WF surveillance program with a focus on incremental oil recoveries from multiple stacked-sands. The injection and production profiles were very useful in improving WF conformance. The water injection profile was measured with a rigless tracer string. The production profile was initially estimated using petrophysical properties and fractional flow curves due to the difficulty of running a production logging tool (PLT) from every pumping well in complex multilayer reservoirs. It was important to validate the production profile with a couple of PLT pilot wells. In these pilot wells, we employed a Y-tool for a connection with the electric submersible pump (ESP) on one side; and the other side of the Y-tool served as a pass through for the PLT. The production and injection profiles provided insights for injector-producer well correlations between productive sand layers. Based on the well data, reservoir simulation models were created and have added value to our reservoir surveillance program, significantly increasing oil production, WF sweep efficiencies, and incremental oil recoveries in the mature LCI WF oil field.

Waterflooding presents many unique challenges, especially in the offshore environment. Cost, slot availability, and uncertainty about return on investment limit the number of water injection wells and the use of ideal flooding patterns. Furthermore, water injectivity commonly declines with time due to formation damage. Well stimulation is a routine solution to remove such damage and recover injectivity. This case study focuses on our experience with a mud-acid stimulation of a water injector in the Gulf of Mexico (GOM). When the injectivity index of an offshore water injection well had decreased over time by a factor of 4, a mud-acid stimulation was performed, and significant injectivity was recovered. The well logs show multiple high-permeability layers, which can cause issues with waterflood conformance. A non-flowback operation, also known as bullheading, was decided upon to push insoluble fines into those high-permeability layers to improve waterflood conformance. Forgoing a post-stimulation flowback also decreased the cost of the job, reduced the risk of personnel exposure to acid, and was more favorable from an environmental viewpoint. Water injectivity was monitored with traditional diagnostic Hall plots. The efficacy of the stimulation job was evaluated through Hall plots, calculated injectivity index, and skin. Pressure transient analysis (PTA) was used to determine kh products, reservoir pressures, and skin factors before and after the mud-acid stimulation. This paper presents the successful, bullhead-style acid stimulation of a water injector supporting two oil producers in the deepwater GOM.