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The typical GLR sensitivity curves for gas-lift design and optimization are obtained for a constant wellhead pressure when the system sensitivity study is for a single well system and for a first-stage separator pressure or fixed pressure when the system sensitivity study is for a complete surface production network modeling. In this paper a production analysis for a six gas-lifted wells system with a new representative curves for gas-lift optimization is presented. These new representative curves were obtained for the complete surface production network modeling that links the well models with the surface network model. Two cases are analyzed:All the six wells are operating and flowing simultaneously andOnly one well is operating and flowing alone. The representative curves for each case analyzed were compared with the typical GLR sensitivity curves. The results show that the representative curves are in a better agreement with the profile of measured data. Introduction A production system consists of the following major components1, 2.Porous medium.Completion (stimulation, perforations, and gravel pack).Tubing with safety valve and choke.Artificial lift system (pump and gas-lift valves among others).Flowline with choke and other piping components (valves, elbows, and other such elements) from the wellhead to the firs-stage separator. In a single well system, as shown in Fig. 1, the fluids flow from the drainage boundary in the reservoir to the first-stage separator. The average pressure within the drainage boundary is called the average reservoir pressure. This pressure controls the flow trough a production system and is assumed to remain constant over a fixed time interval during depletion. When this pressure changes, the well's performance changes and the well may need to be re-evaluated. The average reservoir pressure changes because of normal reservoir depletion or artificial pressure maintenance with water, gas, or chemical injection. The separator pressure at the surface is designed to optimize production and to retain lighter hydrocarbon components in the liquid phase. This pressure is maintained constant by the use of such mechanical devices as pressure regulators. As the well produces or injects, there is a continuos pressure gradient from the reservoir to the separator. In well design calculations, it is not uncommon to use wellhead pressure for the separator pressure, assuming that the separator is at or very near the wellhead. Such assumptions imply negligible pressure loss in the surface flowline. For long flowlines, especially in hilly terrain, to ignore pressure losses may lead to substantial error in the production rate calculation. The production systems analysis is a simple engineering tool to couple IPR with the tubing intake, allowing the determination of surface production rate through the whole production. Mathematically, such coupling allows the reservoir to produce fluids into the wellbore and enables the piping system to lift these fluids into the separator at surface. Additional pressure losses in the production system (e.g., through perforations, induced fractures, chokes, and the like) are accounted for by combining these losses with the appropriate total system losses, such as those in the tubing or reservoir system. This technique is used widely in the design, economic evaluation, and troubleshooting of oil and gas wells. The graphical presentation of the coupled IPR with the tubing intake curves often is called the system graph. As shown in Fig. 2, the intersection of these curves is the solution point or natural flowing point and determines the production rate and the pressure. If these curves do not intersect, the well probably is loading up and artificial lift methods, such as gas lift or subsurface pumps, may mitigate these problems. The system sensitivity study is a major engineering application of production systems analysis. A system sensitivity is defined as the functional relationship of the production or injection rate with any system parameter, such as a tubing internal diameter, gas/oil ratio (GOR), wellhead pressure, permeability, and skin among others. This is accomplished by repeating IPR or intake curves in the system graph for different values of the sensitivity paramenter. Once the parameter is optimized, other parameters are considered. This also is called sequential optimization.

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The two-region hydraulic averaging model was used to analyze the problem of cuttings transport during horizontal well drilling. This model considers a two-phase two region system composed of a moving bed (ω-region) and a stationary bed of drill cuttings modelled as a porous medium (η-region). The ω-region is made up of a solid phase (σ-phase) dispersed in a continuous fluid phase (β-phase), while the η-region consists of a stationary solid phase (σ-phase) and a fluid phase (β-phase). The volume averaging method was applied to obtain the volume-averaged transport equations for both the moving bed and the porous medium regions. These equations are based on the non-local form of the volume-averaged momentum transport equation that is valid within the interface region. The three main flow patterns of the horizontal cuttings transport process analyzed were: Case 1 - fully suspended flow, Case 2 - flow with a stationary bed and Case 3 - flow with a moving bed. The one-dimensional models for all cases were solved numerically using the finite difference technique with an implicit scheme. The numerical results were compared with experimental data and theoretical results reported in the literature and a good agreement was found. Introduction Due to the presence of two phases (solid and liquid) where the solid particles tend to settle at the bottom of the pipe(1), the hydraulic transport of solid particles in horizontal pipes is a very complex physical phenomenon. Such a phenomenon is relevant in several areas, such as the chemical, geothermal, mining and oil industries. In the oil industry, horizontal drilling is used to exploit reservoirs exhibiting thin pay zones to solve the problems related to water and gas conning, to obtain greater drainage area and to maximize the productive potential in naturally fractured reservoirs. However, a major deterrent in horizontal drilling is the reduction in performance of the transport of solid rock fragments called cuttings transport(2). A detailed review of published experimental data reveals that the cuttings transport characteristics change with an increase in wellbore angle. Tomren et al.(3) and Ford et al.(4) carried out experimental work on cuttings transport in inclined wellbores and observed the existence of different layers that might occur during mud and cuttings flow in a wellbore: a stationary bed, a sliding bed and a heterogeneous suspension or clear mud. Leising and Walton(5), Sifferman and Becker(6) and Peden et al.(7) reported that under a certain range of well deviation, the cuttings bed in annuli is unstable. Doron and Barnea(8) carried out experimental work on solid-liquid flow in pipes and observed the existence of three mainflow patterns: fully suspended flow, flow with a stationary bed and flow with a moving bed. On the other hand, numerous mathematical and empirical models for the prediction of cuttings transport in horizontal and directional wells have been developed by several researchers(9–18). However, many of the previous models (two- and three-layer approaches) have been constructed on an intuitive basis rather than on a rigorous analysis of the governing point equations and boundary conditions. Intuitive analysis often leads to hidden assumptions and unsupported simplifications.

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