CO2 injection into oil reservoirs for EOR is well known as one of the most proven and efficient Enhanced Oil Recovery (EOR) processes. The subject study was conducted with the objective of enhancing oil recovery by injecting CO2 into a heterogeneous, low dipping and low permeability carbonate oil reservoir. The required CO2 is captured from a steel plant (Emirates Steel Industry (ESI)) which is part of a large scale carbon capture and injection project. The project entails capturing, dehydrating, compressing, and transporting the CO2 to the oilfields for sequestration and/or EOR processes. The carbon capture from ESI is part of a collaboration (Joint Venture) between ADNOC and MASDAR which will help make CO2 available for potential future EOR operations along with the added benefit of reducing Abu Dhabi's carbon footprint. As part of this initiative, planning of the CO2 EOR process as part of ADNOC's EOR strategy is essential and includes building a phased development CO2 EOR model. The strategy is to breakdown the overall objective into phased developments/projects in order to gain experience in surface and subsurface aspects of CO2 EOR, operations and mitigate risk. The end goal of the phased development is to enhance oil recovery, improve CO2 utilization, and maximize project profitability by implementing more complex operations such as Continuous/WAG CO2 injection, CO2 recycling, and the development of "difficult oil" from flank areas with higher water saturation (transition zone). This paper discusses the benefits and rationale behind building such a phased development model.

A Water-Alternating-Gas (WAG) scheme is a proven enhanced oil recovery (EOR) method. The first WAG project was reported in 1957 and until today more than sixty (60) field experiences can be found in the literature. Most of the published experiences report 5-10% additional oil recovery over waterflood. WAG injection can lead to improved oil recovery by combining better mobility control, improved microscopic displacement, and better sweep efficiency.This study presents a recent field experience where a miscible WAG injection has been designed and implemented with the objective of enhancing oil recovery in a heterogeneous, low dipping, and tight carbonate reservoir. The project has been performed on close-spaced slanted wells and utilizes rich hydrocarbon gas. Since the beginning of the injection, an integrated surveillance program has been applied to determine whether the miscible flood is working efficiently. This program involves observation wells, time-lapse saturation logging, well testing, tracer injection, and i-field technology along with numerical simulation.This paper presents a review of the main findings, issues and lessons learned during eight (8) years of EOR-WAG injection. The paper discusses the project design, the integrated surveillance program and the WAG mechanisms to enhance oil recovery. It also summarizes worldwide WAG experiences based on published field observations.

This paper presents results of phase behavior calculations and simulation of asphaltene precipitation and deposition in The Carito-Mulata Field, based on a reliable experimental support. The Carito-Mulata Field is a complex compositional system which changes from gas condensate at the top to an under saturated black oil in the flank. In this area Asphaltene precipitation becomes a serious problem where plugging of the formation, wellbore and production facilities dramatically affect the productivity and final recovery of the area. To help to prevent the asphaltene precipitation a high pressure maintenance project has been applied by gas and water injection. Therefore it has been considered mandatory to define a representative numerical model to predict the phase behavior of asphaltene precipitation and deposition. As first part of this study a complete experimental plan was carried out involving several PVT analyses, measurements of precipitation onset pressures and plugging core analyses. PVT analysis was used to match a Peng-Robinson EOS in order to reproduce the phase behavior of the system. Asphaltene precipitation as function of pressure was modeled by a pure solid model which was matched by measurements of precipitation onset pressures. A Solid deposition model was matched based on core analysis to reproduce the reduction of porosity and permeability by asphaltene deposition. At the end, a simulation study based on a radial single-well and a 3D model was carried out to validate the predicting model and analyze the Impact of the asphaltene deposition in the well productivity and how it affects the efficiency of different production strategies. It was compared to the impact in the design of production plans taking into consideration the asphaltene modelling and not taking this into consideration. Also it showed how the reported observations in the field, in Lab and in the literature were adequately reproduced.

Historically, field development plans are determined by reservoir production profile generated in standalone subsurface models using a simulation-based forecast. The resulting oil production profile is commonly over estimated because the constraints imposed by the infrastructure capacity on the surface network are not captured appropriately. Moreover, reservoir simulation engineers are forced to apply many simplifications to represent the backpressure impact of topside facilities over the reservoir deliverability. A common practice is to constrain the model, assigning the same minimum bottom hole pressure or well head pressure to all wells and thus misrepresenting the actual wells' behavior. In general this approach may lead into poor development plans, suboptimized system designs, incorrect budget estimation, over expenditures, and so on; all of these issues will impact the overall asset performance and hydrocarbon recovery. Integrated asset modeling (IAM) is a holistic approach that allows upstream and downstream components to be modeled together in order to accomplish a comprehensive production forecast on truly surface constraints. This paper contains a smart field case that demonstrates how coupling subsurface and surface models can effectively improve production forecast accuracy and leverage production optimization from well to asset level in order to provide decision support that takes into account the complexities of interactions between upstream and downstream domains. This work addressed problems such as: the impact of fluid composition variation over time, the interdependencies between wells sharing facilities, the effect of the production strategy or reservoir guidelines over total field production when multiple reservoirs are connected to a surface network sharing common capacity constraints, and optimization of the artificial lift strategy in place. After economical evaluation, it was possible to redefine a development plan considering surface constraints and actual production profiles that optimally extent production plateau for the next 10 years. The value of having an IAM is that it allows for the evaluatuation of the relative impact of downstream and upstream interdependencies over time, thus enabling comprehensive assessment of a wider range of scenarios and development opportunities. This is turn shall contribute to maximize asset profit and generate opportunities to sustain production based on economic and financial indicators.

El Carito field is a giant, deep onshore reservoir in East Venezuela; and it is the second largest field in the north of Monagas basin. Field exploitation started in 1986, and it has been subject to a huge gas injection project to maintain 100% fluid replacement as the optimal exploitation strategy. Market thrust, gas utilization guidelines, and production increase expectations were the drivers calling for implementaation of an in-depth analysis of the reservoir's history and forecast performance. The proposed analysis would require the application of novel methodologies for modeling uncertainty and for analyzing optimium scenarios. A multi-disciplinary team for El Carito field business unit implemented an integrated asset modeling (MIAS) methodology for selecting the optimal field exploitation strategy. The objective was to assure optimal short-term field operating strategies in agreement with long-term reservoir management objectives with social and environmental responsibility. This paper describes the methodology used for developing a field operating strategy and a long term field exploitation plan based on the analysis of historic production profiles, drilling and workover success statistics, production enhancement practices, and world-class best practices available for modeling uncertainty and for optimizating scenario. The applied methodology established fast and consistent, integrated support for decisions and identified quick, constructive actions for immediate implementation in the field. These actions were consistent with optimal long-term reservoir management strategy that best utilizes the subsurface resources and the surface facilities. Introduction El Carito field is a giant, deep, high-pressure, onshore reservoir in East Venezuela (Fig. 1), and it is the second largest producing oil field in the north of Monagas basin. It contains a complex hydrocarbon column with depth-varying composition: from free gas to condensate, volatile, black oil, and a tar mat zone. Field exploitation started in 1986, and it has been subject to a huge high-pressure gas injection project since 1996 to maintain 100% fluid replacement as the optimal exploitation strategy. This field accounts for more than 15% of Venezuela's daily oil production and holds approximately 27% of northern Monagas District's oil-in-place. There were two main drivers for the execution of this study. The first was the desire to satisfy increasing demand for gas from the field to maintain and perhaps increase the field's production plateau. The second was to prepare for a possible request to increase field production from well known zones as well as from more indeterminate, virgin zones. On the other hand, natural gas has been found to be the most precious fuel of the new century [Economides, 2004; Rojas, et al., 2005], with an increasing number of market possibilities for the uses of gas. Gas is required for social development, less expensive environmental-friendly transportation, industrial uses, and to fulfill neighbor countries needs. The main challenge for this project was the determination of a field exploitation plan that could satisfy both the shortterm operational objectives and the long-term maximization of hydrocarbon resources. The project was to use all available multi-disciplinary knowledge and consider all feasible exploitation scenarios in the shortest period of time. The main objective of this paper is to present a summary of the applied methodology for obtaining the 20-year field exploitation plan, considering simultaneously:multidisciplinary risk and uncertainty analysis,minimum environmental risk,endogenous social development, andmaximum net present value created.