The Auca field, located in the Amazonian region of Ecuador, started production in 1970, reaching a peak of 75,000 BOPD in March 2015. By the end of 2015, production declined to 65,000 BOPD due to water cut increase, reservoir pressure loss, and progressive formation damage. In January 2016, Petroamazonas EP (PAM) and Schlumberger (SLB) initiated the Shaya Project with the objective of increasing production and reserves through infill drilling, secondary recovery, and well interventions. The Auca field produces from the Hollín Formation and the Napo U and T sandstones. The latter two normally suffer from pressure depletion due to weak aquifer support, whereas the Hollín formation maintains reservoir pressure due a strong aquifer acting from the bottom. In general, formation damage in the Auca field is caused during drilling and pulling activities due to invasion of drilling or control fluids, but it also happens naturally in form of scale precipitation which has been physically proved, and possibly fines migration which remains a theory yet to be verified. Several workflows, procedures, and research on the nature of the damage have been put in place to resolve the production loss and decline issues associated with the varios potential causes. The selection of the most appropriate damage-removal technique depends on the reservoir and fluid properties, reservoir architecture, production behavior, water diagnosics, well intervention history, well geometry, artificial lift system, and, most importantly, the nature of the formation damage. From the reservoir and production engineering perspective, understanding formation damage and identifying its root cause is a key for designing the appropriate solution. After 18 months of intensive activity with drilling and workover operations, the production of the Auca field is close to 72,000 BOPD. If the operator had decided to stop activities, the production baseline would be at 35,000 BOPD. This means that, at present, the project has contributed a net incremental of 37,000 BOPD, of which approximately 30% corresponds to damage-removal jobs. This is a case study on one of the largest producing oilfields in the Oriente Basin that shows the typical productivity issues to deal with siliciclastic reservoirs and provides an example of how to select the most appropriate damage-removal techniques.

One of the main challenges in production enhancement in mature fields is finding the optimum method to develop different reservoirs under the best exploitation strategy. Ecuador's Eden Yuturi is a mature field where nearly 15% of the field's production comes from a highly laminated, low permeability reservoir with viscous oil properties. The development of this layer requires hydraulic fracturing to economically produce the wells. Hydraulic fracturing was implemented in Eden Yuturi in 2011. The fracturing technology has evolved since then. In 2019, the channel-fracturing technique was introduced, where proppant is pumped in pulses to achieve a heterogeneous placement within the reservoir, creating infinite-conductivity channels. The hydraulic fracture conductivity generated by open channels is higher than a conventional proppant pack. In conventional fractures, flow through proppant is described by Darcy's law; however, for an open fracture channel, the Navier-Stokes equation is applied, implying that effective permeability is 100 times higher. Based on lessons learned for the past 6 years, some of the best practices include: perforating the entire reservoir in cluster, aggressive fracture designs averaging approximately 60,000 lbs of 20/40 proppant pumped, using resin-coated proppant to reduce proppant flowback and using ESP pumps with more robust stages that are well suited to handle solids production and viscous oil. For the frac design, conductivity is increased from 3,500 md-ft to more than 500,000 md-ft with the channel fracturing technique. The associated dimensionless fracture conductivity increased from 2 to 50, and the resulting fracture width increased by 400%. As a result, the average fractured well productivity index increased by two-fold, resulting in higher production rates from 300 to 500 BOPD, ensuring the required volume to be economic as they decline smoothly, reaching cumulative volumes beyond 300,000 bbl of oil per well. This has enabled the Asset to increase reserves in the last campaigns by 2.5 MMbbl. This result leads the NOC to better optimize their development strategy. Nearly 10 MMbbl are estimated to be recovered from this reservoir. Hydraulic fracturing has made the economic exploitation of this tight layer a reality since the reservoir was previously considered an uneconomic target. Through this aggressive strategy, Eden Yuturi Field has become the pioneer in economically exploiting laminated reservoirs in Ecuador.

The Auca field is located in the northern Oriente basin (Ecuador) with hydrocarbon production coming from Cretaceous fluvio-estuarine and shallow marine sandstones. The field has produced more than 547 million barrels of oil since 1972 and by the end of 2015 the field recovery factor was approximately 14%. In December 2015, the reservoir management and the field re-development activities for the Auca field were awarded to Schlumberger Production Management (SPM) under the name of Shaya project. Since then, to sustain the field re-development activities, an integrated reservoir characterization process has been implemented. In this depositional environment reservoir evaluation can be very challenging, especially when using only conventional well logs. It is proposed in this paper that the acquisition of texture dependent measurements is the solution to improve the understanding of the reservoir rocks in highly heterogeneous environments. Based on our experience in Ecuador, incorporating nuclear magnetic resonance (NMR) in the petrophysical model appears to be the best way to collect the needed texture dependent data. The Rock type characterization in the field was based on mercury injection capillary pressure data. This method enables the determination of pore throat profiles for each rock type and the dominant interconnected pore system, which corresponds to a mercury saturation of 35% in a capillary pressure curve. An empirical relationship was used to relate conventional porosity and permeability to pore throat profiles, and this was used to classify rock types. With the purpose of validating reserves and optimizing the field development plan, a model based on rock type characterization was developed using existing core, log and production data. Additionally, this model was calibrated using data from multiple fields in the basin. The propagation of the model from core to logs was accomplished through a relationship between gamma ray, density, neutron and NMR logs with core porosity and permeability in key wells. These relationships are dependent on rock type, and they were used to extrapolate core characterization to those wells without cores. Maps of rock type distribution were used to classify areas according to their petrophysical properties. These maps were also used to delineate the reservoir limits, helping to validate and identify prospective areas for future drilling and workovers. This paper presents the characterization of the reservoir into rock types by integrating geological, petrophysical and production data through Neural Network Analysis, establishing a fundamental input into and support for the development of the exploitation plan.