This paper shows the evolution of the cyclic steam stimulation (CSS) process in a Colombian heavy oil field. Some challenges have been faced like: low injectivity in the first stimulation cycles, presence of swelling clays, low lateral and vertical continuity of the producing sands, steam channeling, among others. According to the oilfield complexity some strategies are currently being implemented after previous studies of numerical simulation and lab test evaluation: diesel slug to improve injectivity, reduced steam quality in the first cycles to increase steam injectivity, using clay inhibitor during steam injection, reduced spacing in the better zones according to opportunity index map, nitrogen injection in wells with more than six stimulation cycles, high frequency cycles and changes in completion design and drilling scheme among others. The set of lab test, numerical simulation and pilot test have resulted in the following: 1) Use of diesel slug before steam soaking clean the hole improving injectivity, allowing more steam volume injection. 2) Reduce steam quality in first stimulation cycles is useful to increase injectivity without significantly affecting steam oil ratio SOR. 3) Using an index map opportunity help to easily identify areas with the greatest potential for infill wells. 4) Injecting nitrogen with steam in wells with more than six stimulation cycles improve production results due to the pressurization of producing sands. Key recommendations for implementing a CSS process in heavy oil reservoirs with low lateral and vertical continuity of the producing sands, swelling clays and low net to gross are presented in this article. The recommendations range from the first injection cycles to maturity of the process and the search for new production alternatives.

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A mature oil field reservoir is characterized by gathering the geological and petrophysical data with the dynamic data. The product allows the defining of vertical reservoir units and their continuity along the field. Reservoir properties, seals and barriers are determined by pressure data and compared with the petrophysical interpretation.This document presents a profound study on pressure data interpretation and how to integrate this information with a petrophysical-geological model obtained by well log data analysis. The sands correlation, reservoir properties, faults location and vertical seals, are interpreted at first with the well log data (GR-SP-RES-DN-PE) and seismic data. Then the pressure data points are analyzed taking into account the previous interpretation to confirm the sands vertical connectivity, fluid gradients and the fluid contacts. Additionally, the mini PBU transients are diagnosed by means of computer-aided type curves to evaluate flow regimes in the near wellbore region and to calculate the permeability. Finally, a fully integrated static petrophysical model is built based on the previous study.The geological cross section is compared before and after the pressure data integration. Ten recently drilled wells from three different reservoir areas with pressure data available are analyzed and presented in this paper. The pressure data evaluation allows identifying the 4 different formation units and its water oil contact (WOC), according to the pressure gradients. The pressure behavior along the horizontal section permits to estimate the sands continuity and the connectivity between three areas. The static reservoir pressure analysis serves to validate and improve the basic well log interpretation and should be a part of the formation evaluation workflow. In addition, a near wellbore model is a strong tool to support and improve the type curve diagnose and interpretation of dynamic data.This paper provides a great insight on reservoir characterization and the benefits of the pressure logging tool for gathering static and dynamic information into geological models. In many cases formation testing data interpretation is based solely on the spherical flow analytical model. This straightforward approach might bias some features of the near wellbore region, which can only be assessed by pressure transient diagnosis (e.g. pressure derivative). Modeling of formation pressure testing as an interpretation tool strongly improves the near wellbore region dynamic description.