Brazilian Government has proposed a change in the current fiscal regime because of the recent discoveries of large oil reserves in Brazilian pre-salt areas, from royalty/tax system to production-sharing contracts. Implementing the production-sharing system, the government believes that this is the best policy to increase gains to be transferred to society. Although, the production-sharing system is not currently clearly defined in Brazil, some debates among companies and government are occurring. Some questions may arise when comparing royalty/tax and production-sharing contracts under the company's point of view: 1) Are the appropriate oil exploitation strategy different for each fiscal model regarding configuration of wells? 2) What are the risk and return created by each fiscal regime for companies? The aim of this paper is to present a comparative analysis considering risk and return of the optimum exploitation strategy for both systems, regarding number of injectors and producers and their allocation in the reservoir. The methodology consists of: (1) selection of a typical oil field from pre-salt area; (2) optimization of an oil exploitation strategy through reservoir simulation aiming to maximize company NPV for a single deterministic scenario for each fiscal system; (3) modeling of uncertainty in oil price, capital and operating costs etc. (4) Monte Carlo simulation and quantification of risk and return (Expected Monetary Value, EMV) of royalty/tax and production-sharing systems (5) sensitivity analysis of parameters of major interest. Results indicate that the optimal production strategy to maximize NPV is different for each fiscal system. The uncertainties in the economic scenario considered in this work influence the EMV significantly. Moreover, it is also important the cost structure of the oil field and how production is shared between the parts involved over time.
After recent discoveries of large oil reserves in pre-salt areas of Brazil, the government has proposed a change in the current fiscal regime from Royalty & Tax to Production Sharing Contracts. The government wishes to implement the production sharing system to earn higher revenues, believing that this is the best policy to improve State gains to be transferred to society. In this new environment and focusing on the oil production strategy selection process, it is required to know if: 1) the production strategies are the same or different for both models 2) the same technical-economic indicators are suitable to be used to select the optimal production strategy in both systems. Nowadays, there is no clear convergence of points of view to answer these issues, although some debates among professionals and government are taking place. The aim of this paper is to present a comparative analysis of the optimum exploitation strategy for both fiscal models, regarding number of injection and production wells and, their allocation in the reservoir. This objective is accomplished following a production-strategy optimization that combines manual and automatic procedures to maximize the company NPV accounting for the assumption of a known behavior of oil prices. Sensitivity analyses of government take to oil price and cost recovery limits are carried out. The results show that the choice of the optimal-production strategy to maximize NPV depends on the fiscal regime. In addition, the government take is reduced with the increase of oil prices. For any oil price, the government take in the production sharing contract system is higher than in R&T, so that it is one of the reasons why it is more interesting from the government's point of view. Besides, the increase of cost recovery limit implies in a reduction of the government take up to a stable value.
Smart completion allows higher operational flexibility for the development of petroleum fields than the conventional completion. However, the real benefits of this technology are not always clear. In order to compare advantages and disadvantages of each type of completion in the exploitation of oil fields, it is necessary to optimize the production strategy for both options. This paper presents a methodology to optimize strategies with reactive and proactive control valves in smart wells; the same methodology is applied to conventional wells in order to compare the different behaviors. This methodology aims to help the manager in the decision of choosing between conventional or smart wells in developing an oil field. An evolutionary algorithm was coupled to a commercial simulator to search for the maximum of the objective function, the Net Present Value (NPV), determining the optimum water cut of producer smart wells for each valve (proactive control), for all valves (reactive control) or for a whole producer conventional well. Then, a fair performance comparison between both types of completions is done. The case studies are simple in order to make clear the difference between the cases. They are classified in reservoir models regarding different heterogeneities, type of oil and under economic uncertainty. Uncertainties in oil prices and in water production cost are considered through three economic scenarios: optimistic, probable and pessimistic. Results show that smart wells are able to increase production time, cumulative oil production and the NPV, also decreasing water production and injection in some cases. The results show higher benefits in using smart wells in high heterogeneity and light oil reservoirs to increase oil production and maximize NPV. Smart wells differ greatly from the conventional ones in pessimistic economic scenarios, where there are operational restrictions due to the unfavorable scenario.
Water-cut prediction by reservoir simulation can be used as the main parameter to determine well shutdown time. In general, analytical formulations are used to determine the maximum water cut that a well can reach and this value is used as a monitoring parameter in reservoir simulation. Moreover, water-cut value can be a good indicator to evaluate field performance and it can be used as a variable in optimization process. This paper presents a methodology to optimize production strategy using water cut as a parameter to shut down wells and smart completions as a variable of the optimization process and as an economic indicator to evaluate strategy efficiency. A discussion on the use of water cut in a reservoir simulation is made, regarding the benefits and limitations of the use. The results show that using only analytical formulation to determine the water cut to shut down wells and completions is not a good approach to maximize production strategy Net Present Value (NPV). On the other hand, the optimization of well and valve operation using water cut significantly improves the NPV. Water cut is successfully used to indicate strategy efficiency and to suggest strategy modification. The results also show that it is necessary to be careful in the use of water cut in an optimization process, because it can present several limitations. This study may help engineers to decide if it is necessary to run an optimization process to determine the parameter used to shut down wells. Furthermore, the results show the importance of a good estimation of the time to shut down wells and completions to reach the optimum potential of a production strategy.
The use of portfolio theory has been appointed as an important tool for economic risk management in the O&G industry. There are only 3 input parameters: (a) mean return; (b) standard deviation of return; (c) correlation between pairs of assets, projects, prospects, etc. Although simple, one practical problem with the application of this model is the estimation of correlation because there is no historical data as in the case of financial assets. This paper presents a methodology for the estimation of linear and rank correlation between E&P oil and gas projects through the following steps: 1) Estimate the mean and risk of each project; 2) Identify the variables that are common to two projects such as oil price, fiscal regime, etc; 3) Simulate the return of each project; 4) Estimate the correlation between projects.This model is applied to estimate the mean and risk of a portfolio of 3 projects typical from the deep-water in Brazil with reserves of 346, 629 and 694 million barrels. The fiscal model is based on Tax & Royalty. For all these projects, production strategy and production curve come from reservoir simulation.Alternatively, correlation between return of projects is assumed subjectively (a typical number is 70%) but with this model it can be estimated in a much more sound way. Results indicate that main determinants of correlation are fixed cost, variable cost and oil quality. With this information, managers are able to select best portfolios -for example, by means of farm-in and farm-out -in order to create value for stakeholders considering not only means, but also risk and possible benefits from diversification.
The selection of the best oil production strategy consists of finding the optimal number of wells and their locations, well flow-rates, well opening schedule, platform production size, water treatment capacity, etc to maximize NPV, RF, among others. But, there is always uncertainty in the determinants of these variables and also there will be risk. An increase in oil price may change the optimal number of wells. Similarly, with an oil price decrease, it may be necessary to shut-in some wells. The problem becomes more complicated because the production strategy must be defined at the early stage of the development. Then, management may find it suitable to pay for some flexibility that could be useful in the future and improve the project profitability. These flexibilities have two benefits. First, they reduce the risk of the NPV of the project. Second, they add value to the entire project. To estimate the value of flexibility in the management of an oil project towards profit maximization, we consider an offshore oil field with 28 °API and 98 million cubic meters of OOIP. Because oil price fluctuates, management finds suitable to start production with 16 wells and a platform with liquid production capacity of 17,700 cubic meters per day. This platform has extra-capacity that can be used in case management needs an increase in oil production, which, is strongly dependent on oil price. This extra-capacity adds value to the project since it allows management, the option to increase production in case of an increase in oil price. To evaluate this flexibility, NPV method is not the right tool, but real options models. We analyze the possibility to exercise the flexibility to increase production by drilling more wells in years 1, 2 or 3 after the opening of 16th well. In this study, we conclude that the value of the flexibility to expand production is not very high. This is unexpected, since in most cases in literature, the value of flexibility is above 25% of the static NPV. The reason, in this case, is due to the high investment in drilling wells and the low impact on the production curve.
After the discovery of large oil reserves in pre-salt areas of Santos Basin, the Brazilian government has changed the fiscal regime from royalty/tax system to production sharing system, which is the one already adopted in countries like Indonesia, Colombia, among others. The proponents of this idea say that it is necessary, because after these discoveries the exploration risk in this area is low. The proposed fiscal regime has created an intense debate among professionals, institutions and government. Who will be the winner? Who will be the looser? How much will be the loss or gain? At this moment, there is not clear convergence of viewpoint about the forecasting of the impacts on new investment. The reason for the implementation of production sharing system is because government wishes to capture a larger share of the profits. How? Politicians believe that the following policy could bring more benefits to government: in the bidding to new productions projects, the winner will be the company that offers the largest share of production to government. Then, the main objective of this paper is to investigate the behavior of the proposed fiscal regime in terms of production profile, NPV and risk, etc. In order to carry out this study, first, a typical oil field project from the pre-salt area is selected, whose characteristics are: large reserve, located in deep-water and bellow salt layer. After that, it is carried out an economic evaluation, comparison and risk analysis of a production strategy considering both regimes of concession and production-sharing. It is concluded that, it is not always that production-sharing agreement is superior, since it depends on the share of government in production, investment level, operation cost, among others.
Economist and finance professionals are always concerned with risk in variables like NPV, IRR, payback, ROA, ROE and other indicators used by analysts and management team. But, in the day-by-day, discussions about risk in operational availability, loss of production, concern of failure of equipment on production, environmental impacts, damage due to hurricane and storms, among others. Currently, operational risk is not so discussed in the oil industry as financial risk, but it may cost billion to insurers and oil companies in events like Katrina, Ike and others. In this paper, the operational risk of an oil project, its impacts and ways of protection to reduce exposure are studied. The approach is composed of the following: Macro-modeling of the reliability and operational risk of the oil production system (platform, pipes etc.); Simulation of reliability, availability, downing events etc. over a period of interest (usually, 20 years); Estimation of loss of production and its associated cost with failure of equipments; Use of financial derivatives to hedge loss due to operational risk. This model is applied to an oil production project similar to those ones of the Brazilian offshore basins. We find that derivatives could be a direct way to hedge oil companies against loss, using financial instrument already traded in the market at a very competitive price, when compared to a traditional insurance policy.
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