Many works on dynamic models for the maximization of the Net Present Value (NPV) on upstream projects have been published in recent years, originating in the academy as well as the industry. These models usually treat the effort considering either the exploration stage or the development stage of the petroleum field, but not both together. In this paper, two purposes will be pursued: (1) Investigating of the optimum net present value in the upstream project considering both exploration and development efforts simultaneously, and (2) Comparing the impact of this model against the dynamic models that deal with the sustainability of the exploration of exhaustible resources according to Hotelling's rule (1931). On the first topic, some papers were published by Pakravan (1977), Peterson (1978), Pindyck (1978), Liu and Situnen (1982), and Nilssen and Nystad (1986). The present paper shows a model bearing resemblance to the model proposed by Nilssen and Nystad (1986) but without the simplifications assumed by it. For this reason, the model proposed here may be more realistic. Some of the questions addressed in this work are: (a) What is the optimum exploratory effort for a petroleum field? (b) For how long do the exploratory efforts deserve investment before the beginning of the development stage? (c) What is the appropriate value of the reservoir recovery factor? The maximization of the NPV is represented by an objective function. The influence of the parameters in the calculation of the proposed objective function is shown by means of sensitivity analysis. Among the the companies in the world exploring petroleum, several do not usually adopt a methodology combining the exploration and development efforts. Filling this gap in the methodology is the main motivation for this work, which intends to disseminate the use of the combined model in the analysis of the economic viability project of the upstream area. Finally, in the conclusion section, among other suggested guidelines, indications are given as to which parameters from this model deserve more attention from persons making hard decisions in the upstream projects, and which information from the exploration and development of a petroleum field must be collected from existing data, or specially treated.
The present work has two main purposes: (1) investigating the optimum exploration and development effort of a petroleum field by the maximization of the net present value of the investment, and (2) comparing the impact of this maximization model against the dynamic models used in activities of exploitation of exhaustible resources, particularly the Hotelling model (1931). The optimum effort, both in the exploration and the development stages, is simultaneously assessed. This type of modeling is not yet widely used in the petroleum industry; instead, these maximizations are in general treated separately. The issues in any search for optimization of exploration and development activities are: (a) what is the optimum exploratory effort of a field, expressed in number of wells? (b) how much time should be invested in the exploration of a field before starting development proper? (c) which optimum rate of the field reserve should be extracted per year? Of course some simplifying assumptions will be made, in order to allow appropriate simulations of the models, but care will be taken not to distance the model from reality. The first assumption is that there is a relationship between the value of the discovered reserves of a petroleum field and the exploratory effort spent in the discovery. This is reasonable, and it is observed in practice by all hydrocarbon exploration and production companies in the world.
Both in the academic environment and in exploration and development projects prepared by companies, it is common to find models that deal with exploration and development optimization efforts in a segregaded way. One of the reasons for this is the complexity in information treatment demanded by each stage. A combined treatment of both efforts is certainly possible, although the parameters needed for a combined model are difficult to measure. The concluding section indicates which parameters must be more accurately determined by those specializing in assessing E&P projects in petroleum companies. Some important works published on this topic are: Liu and Situnen (1982), Pakravan (1977), Peterson (1978), Pindyck (1978), and Nilssen and Nystad (1986). The model adopted in the present work has similarities to that published in 1986 by Nilssen and Nystad, but some of the simplifying assumptions of these authors were dispensed with. It is believed that this can confer a greater adherence to reality than recently published models.
This paper discusses the recent patent application filed by EnCana Corporation on the use of air injection to improve the performance of steam assisted gravity drainage (SAGD).
EnCana's SAGD/Air Injection process employs standard SAGD well-pair infrastructure. It optimizes between the ability of steam to preheat the reservoir during SAGD and the superior (follow-up) oil displacement efficiency of in-situ combustion.
Operationally, air injection is initiated after thermal communication has been established between well-pairs with steam. One interesting feature of this operating strategy is that down-hole bulk separation of oil and gas occurs which facilitates (a) efficient monitoring and control of the combustion, (b) design of surface facilities, and (c) corrosion mitigation.
Laboratory combustion tube tests are presented that confirm the ability to initiate and sustain combustion, as well as mobilize residual oil saturation to steam, within a SAGD chamber. These experiments were initialized at oil saturations and conditions representative of those in a steam chamber. The residual oil saturations were determined from a full-hole core taken in the vicinity of a mature SAGD well-pair at Foster Creek.
Numerical simulations of post-SAGD air injection are presented that suggest the ability to displace and produce oil banks between well-pairs and that recovery factor can be increased up to 8% of the original oil-in-place over conventional SAGD.
The simulations show oil production rates and recovery factor are expected to increase with higher air injection rates. However, instantaneous air-oil ratios, which are indicative of operating costs, also increase. Thus there is an optimum continuous air injection rate that maximizes profitability. Simulations further indicate that it is possible to recycle flue gases in the injection stream without affecting oil recovery.