Summary A generalized semi-analytical productivity model, accounting for any well and reservoir configuration has been constructed and presented recently. The model allows for the production or injection prediction of any well (vertical, horizontal, deviated) and reservoir configurations in both isotropic and anisotropic media. Partially completed wells can also be simulated. A concern in modern reservoir management is the potential desirability of multiple horizontal laterals, frequently emanating from the same vertical well. Once pseudosteady state is reached, the productivity index differences among various well configurations are diminished. Thus, multiple laterals in higher-permeability formations, draining an assigned "box," may not offer incremental benefits. However, at early time and under transient conditions in low-to-medium- permeability reservoirs, the relative productivity improvements provided by multiple laterals may result in sufficient incremental benefits to warrant their drilling. This paper presents a series of parametric studies for a range of reservoir permeabilities and permeability anisotropies for various multiple well configurations. The desirability or lack there of for these configurations is demonstrated. Introduction A comprehensive multi- and single-well productivity or injectivity prediction model was introduced recently that allows arbitrary positioning of the well(s) in anisotropic formations. Such a flexible and generalized model can be used to study several plausible scenarios, especially the economic attractiveness of drilling multiple horizontal wells-which in some cases may be multiple laterals configured from the same wellbore. Clearly, multiple wells (vertical or horizontal) in the same drainage area will interfere with each other. This interference will be felt earlier in higher permeability formations, and the relative economic attractiveness of the multi-well configurations may begin to diminish early. The lower the reservoir permeability, the later the interference will be felt.

A multiphase flow meter named PhaseTester has been developed for determining oil, water, and gas production rates simultaneously. This new approach of well testing delivers significantly improved data quality and availability, allowing quick well performance trend analysis and immediate well diagnosis. Rapid, accurate production diagnosis allows timely decisions without prior well information or standard rate stabilization periods resulting in shorter, more reliable well tests stored in an easily accessible, user-friendly database. The PhaseTester provides a comparatively lighter operation unit and reduces risk of human error resulting in improved safety. Compared to conventional units, the physical size of the PhaseTester is usually half the size and the extensive pressure lines and safety devices are reduced. The meter is environment friendly since all the well effluents are returned to the production flowline without the need for separation or burning of hydrocarbons during the test. Obtaining periodic, accurate well test measurements is the key factor in Vico Indonesia Indonesia's well production optimization. The PhaseTester was introduced to monitor and optimize the production performance for gas lift wells. Changes in well performance were observed immediately allowing the operations engineer to quickly analyze the production characteristics and make decisions based on true accurate real time test data. Selected case histories demonstrate the results of these tests. Introduction Vico Indonesia operates the Sanga-Sanga Block in Indonesia as a Production Sharing Contractor to PERTAMINA, the Indonesian National Oil Company. The Sanga-Sanga Block is located in the Mahakam delta of East Kalimantan, Indonesia (Figure 1) near the city of Balikpapan and consists of four major fields producing approximately 1.3 BSCF/d of gas and 50,000 STB/d. Periodical well testing is the key factor in monitoring well performance. Two conventional trailer test units have been used for the past three years resulting in testing on average only two wells daily. The PhaseTester provides the freedom to acquire more daily well tests. The unprecedented ability of this multiphase flowmeter to accurately perform instantaneous flow rate measurements in challenging slugging flow conditions allows operations engineers to evaluate in real time the effect of small production setting changes (choke sizes, gas lift volumes and pressures, etc.). A gas lift performance curve can be generated rapidly and the operator can leave the well on the maximum production setting immediately after the test. Multiphase well testing provides well data in a digital format that can be interpreted and stored quicker than a standard test separator. The fast acquisition systems monitor a well's 'heart-beat' throughout the test displayed in real time. This provides the capability to detect production trends as they occur allowing the user to terminate testing as soon as adequate information is obtained rather than analyzing data after a pre-determined test period. Fluid property or flow regime changes do not affect the flow rate measurement.

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Drilling multiple-lateral wells and employing intelligent completion systems would very likely lead to considerably higher productivity and increased recovery at relatively low incremental costs. Completing such a well system is a challenge and today it is still considered an extravagant effort. An important reason is that the performance of wells with multiple-lateral completions has not yet been investigated fully. There are several potential configurations for multiple-lateral wells, including planar, multi-planar, branches etc. The reservoir geometry and especially the areal and vertical-to-horizontal permeability anisotropies are critical. Using a versatile simulation model, the calculation of the multiple-lateral well performance is presented. Based on example calculations, optimum spacing, length and number of sidetracks are identified for various reservoir conditions. Shape factors for a number of well configurations are presented. Introduction Multiple-lateral well systems have become a compelling recent topic in the petroleum industry. The reason is that these wells can provide several interesting, and previously inaccessible, opportunities to drain a reservoir efficiently. The idea of spanning a bundle of drainholes out of a single hole and connecting these drainholes with the surface is an appealing possibility. Similarly, drilling one or more horizontal sidetracks from an existing vertical wellbore is a means to enhance the production of the well. Although costly to drill and fraught with operational challenges, these wells may provide better economics than stimulating a specific horizontal well or drilling new wells. Obviously, any decision to drill (multi-) laterals should be based on careful evaluation of the expected well system performance, operational and economic risks, possible production scenarios and, very importantly, (selective) wellbore management and maintenance of the individual drainholes. The technology to drill lateral well branches (often short radius and often using coiled tubing) is available today. However, selection of the right candidates and production and completion technologies is critical. Thus, several new developments and improvements of existing concepts can be expected in this area. This paper highlights reservoir engineering and production aspects of multiple- lateral well systems. Uncomplicated methods for calculating inflow performance of various well configurations are presented and important production engineering concepts are discussed. Classification of Multiple-Lateral Well Systems Multiple-lateral systems are wells with more than one lateral leg branching into the formation(s). This general definition gives rise to several configurations listed below and pictured in Fig. 1:–Multi-branched wells (Fig. 1a)–Fork wells (Fig. 1b)–Several laterals branching into one horizontal "mother hole" (Fig. 1c)–Several laterals branching into one vertical mother hole (Fig. 1d)–Dual opposing laterals (Fig. 1e)–Stacked laterals (Fig. 1f) Selection of the most beneficial well system for a given reservoir is the challenge. The available systems can be and have been classified according to drilling (curvature, workover vs. coiled tubing rig, conventional vs. slimhole), completion (cased and perforated or slotted liner vs. open hole), production, and reservoir engineering aspects. This paper will be limited to the reservoir and production engineering aspects. P. 609

In predicting and optimizing the performance of single and multiple wells, or complex well architecture, within a drainage or flow unit, we have favored benchmark analytical or semianalytical models. Recently. a general productivity model has been constructed and presented that allows for the performance prediction of any single- and multi-well configuration within any reservoir geometry in both isotropic and anisotropic media. Such an approximation is known to have limitations when applied to two-phase reservoir flow. This work used a numerical simulator to generate IPR's for horizontal or multibranched wells producing from a solution- gas-drive reservoir. First, a base case is considered with typical fluid, rock, and reservoir properties. Then, variations from the base case are investigated. These variations cover a wide range of fluid, reservoir, and well characteristics. The effects of numerous reservoir and fluid properties on the calculated curves are investigated. Bubblepoint pressure and reservoir depletion have a significant effect on the curves. A generalized dimensionless IPR based on nonlinear regression analysis of simulator results is developed. This IPR curve is then used to predict the performance of horizontal and multibranched wells in a solution-gas-drive reservoir combined with our productivity model. For relatively low bubblepoint pressures, the curves coalesce on Vogel's classic relationship. For higher pressures they deviate substantially. P. 239