This paper presents an analysis method of the transient pressure behavior of dual lateral wells. Conventionally lateral wells have been analyzed using horizontal well analysis techniques. As we will show in this paper, that if the phase angle between the two lateral sections differ from p, they can not be treated as horizontal well and such practices any result erroneous reservoir properties. An infinite conductivity solution for dual lateral wells was developed by coupling both; the infinite conductivity horizontal well model and the superposition concepts. From the sensitivity analysis study, it was found that infinite conductivity solution for dual lateral wells is affected by the horizontal anisotropy, phasing of the lateral sections, dimensionless horizontal separation, mechanical skin, wellbore storage. It is less affected by the dimensionless vertical separation and the contrast between the dimensionless lateral lengths. Transient pressure behavior of dual lateral wells appears to be more pronounced in the cases:for a phase angle decreasing,for a horizontal separation decreasing, andfor a horizontal anisotropy increasing. The effect of the phase angle decreases while increasing the dimensionless lateral lengths and horizontal separation. The effect of the horizontal anisotropy on the pressure behavior is more pronounced for high phase angles. The wellbore storage dominated flow period tends to be more affected for small dimensionless lateral lengths, LD. The effect of unequal lateral lengths and vertical separation are pronounced only at early times. The intermediate time pseudoradial flow period displayed by dual lateral wells is more distinguishable from the wellbore responses in the cases of a large phase angle and a high value of the horizontal separation. It is worthwhile to note that the responses of dual lateral wells having a phase angle, ß=p, may be viewed as an equivalent single horizontal well. Also Tiab's Direct Synthesis (TDS) technique methodolgy for dual lateral wells has been developed, which adds to the analysis of such wells. Few examples are solved in a step-by-step manner, which demonstrate the use of the method developed. Introduction The productivity improvement expected from horizontal wells is usually proportional to the length of the well. As the length of the horizontal well increases, drilling and well control become extremely difficult. In addition, transportation of a large volume of fluid along a long horizontal borehole results in considerable wellbore pressure losses affecting the productivity. In term of the well coverage, dual lateral wells are expected to provide an excellent alternative to the long horizontal wells. A thorough treatment of the well itself based on accurate computational methods for analyzing and predicting the well performance is needed for better understanding the dual lateral pressure behavior. Practically, the main characteristic features of the responses is that the dual lateral wells may be viewed and analyzed as an equivalent single horizontal well. However, this approach is a great simplification and is suitable only for certain phase angles and anisotropy ratios. Therefore, this approximation is restricted to a specific reservoir-well configuration and its use may introduce significant error in estimating reservoir parameters. For this purpose, we present a semi analytical dual lateral model based on that of the horizontal wells. According to our knowledge, there does not exist such a model to date. Literature review Over the last decade, a considerable amount of work has been published on various aspects of multilateral wells. Most of these works have been presented on the performance of multilateral wells as means of new technology to improve productivity. But only few of them treat the transient pressure behavior of multilateral wells. Karakas, Yokohama and Arima(1) have presented an interpretation of several transient tests conducted in multilateral wells. Using a numerical solution, they indicated that most multiple drain hole systems can be approximated by an equivalent single layer, single drain hole systems.

As a Brown Field, located in North Africa. Approximately 95% of Zarzaitine field wells are utilizing Gas Lift as an artificial lift method. The field has a challenging situation to optimize its Oil production; A detailed understanding of the production sys tem thermohydraulic, facility design and the amount of gas injection will ultimately have a major effect on production target. For this purpose, modeling the entire production system was necessary to properly account for the interdependency of wells and surface equipment and determine the system deliverability as a whole by optimizing Gas Lift injection. This paper presents an approach which was introduced for the first time in this field to ensure gas is used efficiently using a multiphase flow simulator for wells and pipelines to model the entire field Production Network in addition to the Oil producing wells including Gas lift mandrels. The model includes 112 Gas Lift wells with a detailed Gas Lift valves system currently on production, each one has been matched against the latest valid well test, Seven Separation Centers, Production gathering pipelines, Production gathering Center and Gas Lift Injection Center. The study has been executed in three major phases: Well Modeling & Calibration, Network Modeling and Gas Lift Optimization. Total Oil production rate has been defined as an objective function during the optimization phase where the total Injected Gas Lift rate for the entire network and for each individual well have been defined as varying parameters; By having a network model calibrated against field data representing the operational conditions of the asset, performing Gas Lift Optimization was the natural next step. Subsequently, by simulating the production system with different Gas Lift Optimization scenarios to maximize Oil production rate under specific surface facilities constraints using the Production Network Model, a better insight of how gas injection rate affects the total production and an understanding of whether a smarter allocation of the current available gas is possible in comparison to the different scenarios has been accomplished. As a result of this Optimization by applying some local and global constraints a 10% Oil production increase has been achieved. This practice has been shown to be successful as predictive technique in a variety of ways specially for such brown fields with more than 60 years of production history. As a next step, to properly manage the real potential of Brown fields, a full field Integrated Asset Model could be created to capture the interaction between the surface and the sub-surface. This model will account for the complex interactions between reservoir, wells and pipelines.

No abstract