TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractEvaluation of the chemical flood potential in the Chihuido de la Sierra Negra field, Argentina, has been carried out using several different recovery scenarios. This field has been submitted to extensive waterflooding for several years, and surface facilities have been designed to recycle produced brine as injection brine. The use of produced brine, as chemical solution make-up water is therefore very advantageous from both an operational and economical point of view. However, the formation brine contains around 110,000 PPM Total Dissolved Solids with around 2,800 PPM divalent cations. This makes the selection of the proper surfactant extremely difficult. Processes such as Alkali Surfactant Polymer Flooding have been considered, however, the requirement of large amounts of fresh water as well as softening units in the field adversely affects the economics of this process. This paper will discuss the development of a new anionic surfactant that provides solubility in high salinities and low interfacial tension at low concentration. The Chihuido de la Sierra Negra field history will be briefly described, and the laboratory screening and evaluation of the surfactants, including the interfacial tension properties, the adsorption, the core evaluation, and the performance of the flood will also be discussed.The significance of this development is that it could lend feasibility to EOR projects that would be deemed uneconomical because of water treatment and handling costs.

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.

This paper describes the processes incorporated during the simulation study of the Chihuido de la Sierra Negra Field in Argentina, which is presently the largest oil field in the country. The field was discovered in 1968, and an aggressive water injection program was started in 1995. So far the oil production from this field is 65 million cubic meters and the water injection is 158 million cubic meters. The field has two separate stacked reservoirs that are structurally complex with different fault systems and fluids. Both reservoirs are highly compartmentalized with each compartment having different water-oil contact. The upper reservoir is composed of 6 isolated geologic layers, with each being different depositional environments (sand bars, dunes, fluvial channels, etc.). The presence of unconformities and volcanic intrusions further complicate the reservoir communication and plays an important role in flow behavior. Currently, the field has 734 production wells with commingled production from both reservoirs and the isolated zones with in the upper reservoir. Approximately 1250 injection strings are currently injecting water. The purpose of this study was to provide a detailed reservoir characterization to optimize recovery and to create a simulation model with predictive capability that can be used in improving field management. To achieve this purpose a 900,000 cell simulation model was constructed. This paper will discuss some of the challenges encountered during the history matching of the field model. The identification of the compartment boundaries and their associated water oil contacts (57 contacts) required the development of a new consistent approach. This method provided significant accuracy and time savings over the traditional approach of iterating between history matching and reservoir characterization. The overwhelming volume of data and the volume of simulation results for 2200 well strings required special considerations for pre- and post-processing. New tools were needed to quickly modify the simulation arrays and review all the wells in an efficient and timely manner. As the history matching progressed many additional practical tools were developed. This paper will discuss the significance of these innovations and tools to achieve a successful history match in a timely manner. Introduction Chihuido de la Sierra Negra is the largest oil field in Argentina. It is located in the Neuquén Basin at 200 km Northwest of Neuquén City (Fig. 1) This field has three main clean sand reservoirs within the Lower Cretaceous Huitrin formation1. These are the Troncoso Inferior, the Agrio Superior and the Avile members. The measured depth where the producing intervals are located varies from 1100 to 1300 meters. The whole productive oil column is divided into ten (10) geological layers extended in a gross thickness of 200 meters. Fig. 2 shows the geological members and the layers present in this field. The shallower reservoirs (~1100 meters measured depth) Troncoso Inferior and Agrio Superior account for 60% of the ultimate recoverable reserves of the field. The depositional environments in the Troncoso Inferior Member include Aeolian dunes (5T and 4T intervals) and fluvial channels (3T and 2T). The middle portion of the productive column (Agrio Superior) is formed by marine sandbars (3A, 2A, 1A and 0A). The detailed reservoir characterization showed that an unconformity surface exists between the Troncoso Inferior and Agrio Superior members. During the simulation study the unconformity surface was verified to be a flow barrier between the two members. The deepest reservoir, Avile Member, is found at ~1300 meters (MD) and is composed of very productive Aeolian sand dunes. All the geological layers are isolated except 5T and 4T. Certain igneous sheets (volcanic intrusions) were correlated using the well logs that were available in the study area (Gamma Ray, Induction, Density and PEF). These identified intrusions have the potential of modifying the communication throughout the field. Fig. 3 shows an example well log with identified volcanic intrusions.

The Eden Yuturi field, first exploited in 2002, is located in the northeast of the Oriente basin, Ecuador. The field was initially operated by Occidental Petroleum and has been operated by Petroamazonas EP (PAM) since 2006. From its peak production of 83.8 million B/D in August 2004, the field declined and now produces less than 30 million B/D, with a water cut of 92%. In 2014, PAM awarded an incremental production based service contract to the Kamana Services consortium, with the objective of reversing the field decline and increasing the recovery factor by optimizing production and applying enhanced oil recovery techniques.The Lower U in the Cretaceous Napo formation is one of the most important reservoirs in this mature field and has a cumulative oil production of 48.1 million barrels (as of July 2015) from 110 wells. The production is supported by a water drive mechanism and a strong aquifer.The major challenge for the consortium is to define an optimal field development plan that maximizes the current recovery factor of 34%. To achieve this goal, it is crucial to enhance the reservoir characterization by integrating all the available information from multiple disciplines and use this knowledge to understand the fluid dynamics in the reservoir.The sedimentary column of the Lower U is interpreted as fluvial at the base follow by tide-dominated estuarine tidal shelf deposits grading into lower shoreface deposits towards the top of the reservoir. This transition subdivides the reservoir column into different hydraulic units. However, the vertical stacking of these hydraulic units is not present across the whole field, and amalgamation has been observed in specific zones. The fluid dynamics changes inside the reservoir have a large impact on the waterdrive mechanism sweep efficiency, as identified in the pressure and production performance analysis of the reservoir across the area, and differences in pressure levels and water cuts trends are evident.Therefore, a proper stratigraphic characterization is the key to optimizing the field development strategy of the Lower U reservoir to improve the ultimate recovery factor.In this paper, we describe how the stratigraphic characterization has been performed and the final framework obtained by the multidisciplinary team, to be used for the optimized development strategy of the Lower U reservoir.

Over the years, simulation models have been helping oil companies and stakeholders to make investment decisions. However, these models are not always available to help with the field development planning. A fast and efficient workflow performed for the identification of new opportunities in the Pañacocha field is presented. To start the workflow, a conceptual geological model was identified for each reservoir, based on the available data and nearby analog fields. Quality control, updating and reinterpretation of well top data, petrophysical parameters maps (net pay, porosity, and water saturation), and original oil in place estimations were carried out to identify untouched areas. A total of 45 locations that may still contain oil were identified. For the next step, a decline curve analysis was carried out, and well type curves were generated to determine the estimated ultimate reserves (EUR), drainage area, and recovery factor by well. The range of recoverable oil associated with each location was estimated by varying all the parameters involved in the volumetric formula. Finally, the locations were ranked based on their production potential. The selection of drilling targets included the associated geological and operational risk. A base case, based on the contract minimum commitments, is presented. However, this study shows that a more aggressive drilling campaign is possible. In conclusion, this workflow allowed us to have a better understanding of the field potential. Oil in place volumes and recovery factors were updated. Analysis of produced fluids helped to assess reservoir performance. The economic analysis following this study will help in selecting the best option to develop the field.