Well evaluation is the primary method used in the oilfield to determine the true well's production potential and reservoir characteristics. During a well evaluation, downhole parameters are commonly registered using downhole memory gauges, which can only be retrieved and read after the evaluation have finished. The problem with this conventional method is the uncertainty or ambiguity results and the inaccurate data of the downhole parameters; which often lead to inefficient tests times and difficulties for well test interpretation.The use of Fiber Optic for Real-time downhole measurements conveyed on Coiled Tubing (CT) and Nitrogen (N2) Lifting provide a unique live insight that allow us to monitor the well response while production or evaluation is performed, eliminating the uncertainties that surrounds traditional methods. Nitrogen lifting with Coiled Tubing was introduced as an alternative evaluation method for the common Hydraulic Jet Pumping that proved advantages accelerating well response and increasing the accurate of the reservoir data for well evaluation and artificial lift design nevertheless this still faces the delayed on the pressure data and transient interpretation. Implementing the Real Time downhole measures (P, T) is possible to eliminate uncertainties of reservoir parameters that surround well evaluations, adjust job parameters on-site, optimize job resources and time and finally anticipate artificial lifting design. This paper will present the results of the implementation of this new method in the area for well evaluation allowing real-time measurements of down hole pressure/temperature. Combining the fluid lifting with N2 through the CT, reservoir response is continuously monitored; thereby, allowing in advance an adequate design of the lifting system reducing nonproductive time. Real-time measurements and accurately data of the reservoir allow defining if a further stimulation treatment is needed. Actual treatment program can be continuously monitored or modified, to achieve optimal results. The first trial using the system demonstrated that the application can be used with a high degree of accuracy and control for the parameters and treatment designs that are not achievable using conventional techniques as the Hydraulic Jet pumping, gauges conveyed in slick line, joined tubing and/or using surface data to predict downhole behavior.

Secondary recovery by water injection is one of the most popular methods to increase reservoir pressure and sweep efficiency in the industry. It is a cost effective technology in reservoirs such as Shushufindi field, where water, energy and sink points are easily available. This pilot aims to provide proof of concept of water injection in mature Ecuadorian fields. The water injection pilot project was carried out in the central north area of the field, in the lower U reservoir, selected as the target injection horizon due to pressure depletion. The injection started in December 2014 in SHS-246D and SHS-244D and then in 2015 two more injector wells were set up, SHS-247 & SHS-003. These wells are located in a 125 acres area, based on inverted five spot pattern. Secondary projects around the world have shown that the success of any water injection project is based on an exhaustive monitoring and surveillance process, along with using the many analysis tools and plots available. Shushufindi, however, needed a specific tailored toolset that fits the surface operating conditions, one that is able to monitor the variables required to understand the local reservoir hydraulic behavior, minimizes issues in the injection cycle, and provides quality data for the continuous improvement of the water injection pilot. In order to achieve this objective, some variables were selected and recorded in a group of theoretical plots. This was achieved by developing a series of workflows on a production management software platform, centered on an alert system to rapidly identify changes in the monitored injection variables and to respond if needed. This monitoring system allows a quick identification of well plugging issues in injector wells through the use of Hall plots, it also tracks the water quality at different points in the water processing plant allowing adjustments to made to the process to improve the water quality if needed, provides information for reservoir characterization monitoring, Voidage Replacement Ratio (VRR), and determines the water injection response in producer wells by monitoring the production parameters.

The Shushufindi field is the largest oil accumulation (3.8 billion barrels) in the Oriente Basin in Ecuador, and it represents 16% of the total oil production in the country. It was discovered in 1972 and has achieved a current recovery of 1.2 billion barrels of its original oil in place. Its peak oil production was 125,000 BOPD, reached in 1986; since then the production steadily declined. The Ecuadorian government recognized the danger of declining oil revenues, and, in January 2012, the national oil company (EP Petroamazonas) signed a 15-year Specific Integrated Services Contract with Consorcio Shushufindi S.A. (75% Schlumberger, 25% Tecpetrol). During an aggressive optimization campaign performed in the last 10 months, the Consorcio Shushufindi has achieved an incremental recovery of 1.1 million barrels (4,400 BOPD) by rebalancing and optimizing bottomhole flowing pressure over most of the field through increasing the extraction rate. An additional 1.1 million barrels (4,700 BOPD) of production was achieved by performing Electrical Submersible Pump (ESP) upsizings in 24 wells, from a complete portfolio of 34 wells. The Shushufindi revolution demonstrates how an ambitious optimization plan, multidisciplinary integration and collaboration between the operator and the service company can be successful in a mature field despite the associated risks. In addition, this project demonstrates that activities can be performed to increase production at a minimal cost and how to maximize the return on existing assets through the realization of their production potential.

Sand Monitoring workflow was introduced in R field to manage and minimize the risk that sand production poses to the production facility by monitoring the sand production and its resulting erosion rate, and raise alarm immediately when these conditions violates the allowable threshold. The workflow serves as an enabler to the sand management process that are put in place at the field. By leveraging the automation from IO and complement it with additional processes, we came up with a holistic approach that is used to minimize the risk to the production facility. The defined Sand Management methodology starts with the automated workflow processing. The workflow utilizes data from field sensors and processes them to conduct risk assessments, and some mathematical calculation that are based on proven correlations. Based on these processes, the workflow will generate output of sand production risk assessment, calculated erosion rate, estimated remaining pipe thickness as a result from the erosion rate and critical drawdown monitoring. To complement the output from the workflow, additional processes that utilizes the outputs are introduced as part of the sand management process. Some of these additional processes are: Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement.Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring.Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets.Choke health monitoring and estimation based on choke CV and modelling. The sand monitoring workflow has increased personnel efficiency by automating repetitive and tedious work and give out the result in an easily interpreted manner. The automated alarm has been proven to be useful in proactively engaging operations to tackle the problematic matter. Production interruption related to sand production has been effectively reduced by 50% after the implementation of the new Sand Management methodology. The introduction of the workflow into the new methodology uses marginal cost, but maximizes the return on existing asset through the realization of their production potential, as well as proving on how multidisciplinary integration and collaboration between operator and the service company can be successful in a mature field despite the risk associated.

The giant Shushufindi (SSFD) field, located in the Amazon basin of Ecuador is a mature field that has been producing since 1972. In December 2011, management of the field was awarded to Consorcio Shushufindi (CSSFD) by PetroAmazonas EP (PAM) with the signature of a 15 year integrated services contract. At the time of contract signature, field production was 45,000 BOPD from 90 wells. Since then, 109 new wells and 91workovers have been completed by CSSFD, raising production to 90,000 BOPD in early 2016. Along with the implementation of a field development plan, key elements, such as the deployment of new processes, operating practices, and technologies, to address deferred production were identified. Production challenges in SSFD were increasing in frequency and severity, and the need for frequent well reviews became a priority. The processes implemented targeted the reduction of production deferment due to well downhole failures by identifying the root cause, planning for remedial actions, and following-up on execution. An initial field-wide evaluation of production deferment causes allowed implementing the process at a large scale rather than on a well-by-well basis. Project management was applied to prioritize actions and materialize the savings in production and costs. To accelerate implementation, a pragmatic approach based on experience was initially used, after which the process became fully defined and documented. Main areas tackled were Electrical submersible pump (ESP) design and new technologiesTubing design and selectionProduction chemistry program adjustmentsWell monitoring and surveillance using operation support centers (OSC)Well servicing (pulling) operational efficiency The improvements were followed by the collection and analysis of field data and results for a period of 5 years and have resulted in an increase in average well run life of over 1 year. Production deferment related to well failure was also decreased from 4.7% to 1.6% of total production, increasing the oil recovery by 1.3 million STBO. The evaluation of the improvements was done over a period of 5 years (January 2012 to November 2016) where the field data was good enough to carry on the analysis.