Casabe field reservoir characteristics are multilayer, geological complexity, vertical/areal heterogeneity and commingled production. Due large difference in mobility between oil and water (M ~ 20) and the maturity of water flooding, several operational problems have arisen, such as, increase of water cut, channeling, sand production, etc. These problems together with the high remaining reserves and identification of bypassed oil, were the main reasons to evaluate EOR process as a solution to increase the recovery factor. A reduced Cycle Time was created to reduce the time from design to full field implementation which involves the following phases: Screening/Conceptual Design, Pilot Design, Drilling-Workover and Facilities, Operation & Surveillance, Pilot Expansion, Full Field Development Plan, Reserves & FID. This strategy is based on multitask parallel process to allow fast track decision making and activities execution for a fast pilot implementation, which allowed to implement the EOR pilot in 24 months form the screening to pilot Operation & Surveillance. After the screening, polymer flooding was considered for mobility ratio modification to improve sweep efficiency and therefore increase RF. The best producer layers were selected, based on the areal continuity and residual oil in place, as target sands for polymer injection. One pattern was selected for the pilot. Laboratory tests, along with reservoir simulation confirmed the potential of chemical EOR in the selected sands and pilot area. Polymer injection was performed in four injector wells of the selected pattern. The polymer flooding process was monitored in the central producer and in the eight producers of the second line. A surveillance plan was implemented to collect the information required to evaluate, with the lowest uncertainty, the results of this pilot. An observation well was drilled to monitored changes in oil saturation. The surveillance plan was critical to be able to control the polymer injection process, to have a proper technical evaluation of the pilot and to optimize costs during the future expansion and full field implementation. Polymer flooding have increased the RF on the selected area. The fast-tracking strategy for an EOR project execution was successfully implemented in Casabe Field and the pilot was delivered in 2 years proving the concept of 5-year road map it is possible. The reduced Cycle Time (5-year Road Map) could be used as reference for implementation of new EOR pilots in other fields in shorter time and optimizing resources. The workflows used and the analysis procedures created for this pilot could be used as reference for the implementation of future pilots in fields with similar characteristics.

Casabe has been under waterflooding for more than 30 years. The heterogenities of the reservoir and the commigled injection implemented at the beginning of the waterflooding, resulted in early break through times. In 2007, selective injection was implemented allowing to inject separately in each layer and, therefore, to have injection distribution through Injection Logging Tools (ILT). However, producer wells are completed in commigled and with PCP or SRP systems, making difficult access the well to have any information about production distribution. At the current phase of the field development, the production distribution is key information for reservoir management to make decisions about short to medium plans to optimize production. By pass systems has been used in 9 5/8” casings with enough room to set an ESP and a by pass system (Y-tool). In Casabe field, producer wells are completed with smaller casing diameter representing a real challenge due to the lack of space to accommodate an ESP with a bypass system. This paper presents the sucessfull application of Slim ESP with by pass system installed in high water cut wells with 7” and 29 #/ft casing, to run conventional production logging tools to determine production distribution and to identify swept and damage zones, PI per layer, crossflow between layers and not producing zones. The challenge of production logging in this environment was not only related to the type of completion in Casabe field (completions with rods and smaller diameter), but also to the multilayer characteristics and high water cut which needed an especific set of tools and sensors to have the best accuracy in the oil and water distribution per layer. A Production Logging Tool of 1-11/16” and a set of 8 probes for bubble counting was a must to achieve the objectives, so the Slim ESP with bypass system was selected based on this condition. After reviewing several combinations, a Slim ESP 319 series and a bypass system with a drift of 2.087” was selected as unique solution. Producction logging has been perform for the first time in Casabe field with a conventional PLT, with no operational problems and with clear results related to oil and water production distribution allowing making short term decisions such as isolating swept zones, stimulating damaged zones or optimizing injection in delpeted zones, but also allowing to understand the real behavoir of the wells and reservoir with the current completion strategy which help to make medium term decisions about reservoir management and field development.

A new Integrated Exploitation strategy to boost production and incorporate reserves at the Ecuadorian Bloque 61 was put on the table to radically change the production strategy from primary to secondary recovery in only two years timeframe. This was accomplished by drilling appraisal, development and infill wells in conjunction with peripherical and pattern waterflooding. The project departed from reservoir characterization and modeling to identify the potential targets for waterflooding. The identified opportunities were assessed and ranked. Consequently, several pilots were implemented as a proof of concept. Once the waterflooding pilots were in place, the complexity of the reservoir was evaluated. To account for the subsurface uncertainties, a probabilistic approach was followed to do the economical evaluation and risk management for the expansion. Novel facilities configuration, implementation of new completion design and production enhacement techniques, along with a robust surveillance plan played a key role for the rapid implementation of a new exploitation strategy. Positive reservoir pressure response and incremental production were observed within one to three months right after injection started in the pilots. This behavior was similar for the other fields where waterflooding was expanded. As such, new wells drilled and well reactivations in areas influenced by waterflooding has proven to have a threefold increase in expected initial productivity, therefore, the increase of reservoir pressure opened new development opportunities in Block 61 in former depleted reservoirs. The implementation of a new exploitation philosophy focused in secondary recovery, increased recovery factor in about 10%, the contribution from waterflooding is about 30% of the total oil production. Additionally, 50% of the volume to be developed, corresponds to activity to be completed in Waterflooding areas. This waterflooding strategy represents a shift in the exploitation paradigm in the Ecuadorian E&P industry, by going beyond the pilot execution through proper risk and uncertainty management as a path to full-field implementation. To fast-track this deployment of the water injection, a closed loop system was implemented between the water source and the injector to reduce facilities costs up to 80% as no treatment is required for the injected water.

It is a common practice to evaluate an injection pilot before a field-level implementation of waterflooding, but this requires early investment in facilities and construction time. An alternative solution is proposed as a modification of the dump flooding concept: Produce water from a low-salinity aquifer and inject it into an oil reservoir within the same well, using a closed system. The modification of the conventional dump flooding design consists of adding surface monitoring and control capabilities, which for this mature field is a local regulatory requirement A comprehensive process for the completion design considered reservoir, well and operational conditions as both new and existing wells were considered as candidates for these completion systems. The design consists of a concentric completion with packers to isolate both the water aquifer and oil reservoir. Water is produced from a deeper low-salinity aquifer with excellent water quality through an Electric Submersible Pump (ESP) that also serves as an injection pump. At surface, the water rate is measured by a flowmeter and then injected into the same well through a concentric string to a shallower oil reservoir for secondary recovery. A simple closed-loop system at surface eliminates contact with oxygen, minimizing future corrosion problems. The high quality of the water (low salinity, without solids, O2, H2S or Fe) eliminated the need for water treatment. Four wells have been successfully completed using this design, currently injecting at the required rates without presenting any functionality problem. Additional three wells are in schedule to be completed in order to accelerate waterflooding implementation in areas either remote or environmentally sensitive with no nearby water source. In these areas, implementing a waterflooding conventional pattern that requires connecting water producers and injector wells would require lengthy permission processes for long high-pressure lines and additional time for the construction of those water transport pipelines. The completed modified dump flooding wells decreased the implementation time of the waterflooding pilot project from 2.5 years to 5 months. Additionally, the environmental footprint and facilities investment has been reduced by an estimated 90%. This is the estimated cost savings when comparing the investment in dump flooding well construction versus conversion of existing wells to water producers or injectors and the investment in facilities, including water treatment plants, to connect those wells. This paper presents the main design and operational considerations before execution, deployment challenges, and lessons learned and recommendations from the execution of the first campaign

Improving production is a main goal in the industry, mainly in countries where now it is possible to apply accessible technology. Digital Oil Field projects have been successfully implemented worldwide, showing their value in terms of losses reduction and oil production optimization. Annular Gas handling system (AGHS) is part of those projects, aiming to improve well production systems. Gas accumulation in the annulus is a well-known operational condition which may lead, depending on the volume and associated gas, to ESP production system issues (gas lock). With this in mind, a technical team was formed to create an autonomous annular gas handling system with the main objective to optimize production by avoiding gas related issues, but also to reduce human intervention in the process. This is translated into less kilometers driven and therefore less people exposure. The main task of the gas handling system consists in regulate the gas outlet through an automatic valve according to a remote order. This order can be given as a percentage of opening denominated "manual control", or as a value of casing head pressure (CHP), denominated "automatic mode" where the valve keeps adjusting automatically in order to maintain the set point pressure (SP). In this way, the manual operation of the annulus valve from an operator on-field is no more needed. This case solution presents the pilot test results and a feasibility analysis for the expansion of the AGHS Skids. The pilot included two wells in the Auca brownfield: ACAK-182 and ACAK-124, in which an incremental production of 30% and 12% respectively was achieved after pilot implementation. Additionally, manual annular valve interventions were reduced 98% after the automated gas-handling system was tested. This project demonstrated that intelligent, customized and specific solutions enabled incremental production at a very low cost, reducing people exposure by avoiding trips from pad to pad for annular valve manipulation. Additionally, AGHS Skid improved the efficiency of the ESP in 11% and reduced energy consumption in 11% KVA resulting in higher production with lower power consumption. Also, people were able to spend time working on production optimization rather than operational tasks.