This paper shows the results from chemical sand consolidation treatments used in the M1 sandstone as the main sand control method. For a successful implementation of this technique a workflow that combines field data, temperature modeling, laboratory analysis, petrophysics and geomechanics has been developed. Production results reports zero to near zero sand production with almost no impact on well productivity. Pre job design steps used to secure a consolidated reservoir after the treatment are described. Temperature is a key parameter to model since the resin is temperature activated. Laboratory tests and simulated temperature defines the curing time. A step rate test is used to calculate the injectivity index and evaluate the need for an acid stimulation treatment before the consolidation system is pumped into the well. This test is repeated after curing time to evaluate any possible impact on productivity. Determination of the Unconfined Compressive Strength (UCS) of the consolidation sand and critical sand production rate are also included in the analysis to understand sand production potential in the field. Chemical sand consolidation consists of two main components, resin and hardener. The consolidation fluid along with a pre-flush and an over-flush have typically been pumped into the well using production tubing. This sand control method has been proven to be relatively low in cost compared to other sand control techniques and the treatment can be performed in a relatively short period of time. These two characteristics and the positive production results observed thus far makes this technique attractive for upcoming sand control completions with unconsolidated reservoirs with similar characteristics to the M1 sandstone. In addition, conventional sand control methods rely on a particle size distribution (PSD) from a representative core sample for a successful implementation whereas chemical sand consolidation system is PDS independent.

As fields become mature and more laboratory data is available from specific geographical locations, it is possible to characterize, classify crude oils and develop or modify published correlations to better predict oil PVT properties. This paper shows the results from the attempt to classify and to provide calibrated correlations for the Ecuadorian crude oils. This study is divided in two sections, the first one makes a brief introduction to the main Ecuadorian oil fields, then the Oriente basin´s geology is described, geographical and statistical variation of crude oil properties is shown by reservoir and geological play. At the end of the first section, different criteria are applied to classify PVT samples showing that most data lie in the range of heavy oil. The second part uses the minimum square method to modify published correlations to provide relationships that helps the reader to better estimate oil properties in the absence laboratory data. Modified correlations as well as statistical results from the comparison of measured and predicted properties are listed at the end of this section.

This paper presents the results of the most extensive hydraulic fracturing campaign on the same field in Ecuador, along with the methodology appliedto establish the real field production potential and an incremental oil production of 10,000 STB/d. The study started with the review of pressure transient analysis (PTA), resulting in updated values of permeability, skin and reservoir pressure, then conventional and special well logs were revisited to get a consistent approach of reservoir pay intervals. The characterization of formation damage mechanism was performed to confirm and complement the results. Strategic execution of the hydraulic fracturing workovers was implemented for fast track execution and to maximize results. The rigorous and fundamentals-based review showed that additional production potential, on most of the wells in the field, could be achieved by hydraulic fracturing due to the high skin values and the deep penetration nature of the damaged zone. The interventions schedule of producing and nonproducing wells resulted in short deferred production times. All planned jobs were designed with the goal of reaching the maximum production defined by hydraulic fracturing and complete nodal analysis. Most fracturing jobs resulted in folds of increase, FOI, from 2 to 13. The learning curve started from one stage tip screen out, TSO, and conventional long fractures, to two stage hydraulic fracturing, pulsed proppant and propped acid fracturing jobs. Economical evaluation showed that the whole stimulation campaign recovered the investment during the third month of execution. The incremental production outcome from these jobs resulted in ten thousandstandardbarrels per day, 10,000 STB/d, the historical peak oil of the field and the most extensive hydraulic fracturing campaign in the country.

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Underperforming fractured wells are often represented by fracture face damage or choked fracture models. This study shows a different pressure behavior identified from various historical cases in which mixed low- and high-mobility regions are present after hydraulic fracturing. Using available technology and processes to optimize the hydrocarbon production from wells in mature fields, this paper presents the data analyses and methodology used to analyze and discretize the induced damage after the stimulation process. Production performance and pressure buildup data showed anomalous behavior in hydraulically fractured wells. To define this problem, an additional detailed reservoir simulation was performed to reproduce the damage mechanism that was not initially well identified by the pressure/derivative analysis. Various cases were examined to define the damage type, extent, and mobility changes present around the fractured area. Results from these simulations were used in pressure transient analysis software to generate analytical models that mimic the pressure behavior. The analytical models were compared with downhole data registered during well evaluation for validation. Numerical models demonstrated that a low-mobility region was present around the fracture face and more consistent productivity results can be achieved by avoiding the creation of this region during fracture jobs by combining different breakers (delayed, temperature-activated, and fast reaction). Pressure buildup data registered from different wells confirmed that the low-mobility region was not present.