This paper presents the mechanism of scale formation by water in oil fields and suggests an accurate model capable of predicting scaling phenomena in Iranian Oilfield operations due to mixing of incompatible waters or change in thermodynamics, kinetics and hydrodynamic condition of systems. A new and reliable scale prediction model which can predict scaling tendency of common oilfield water deposits in water disposal wells, water-flooding systems and in surface equipment and facilities is developed and present. The development of the model is based on experimental data and empirical correlation, which perfectly match Iranian oil fields conditions. Furthermore the simultaneous deposition of oilfield scales and competition of various ions to form scale which is common phenomena in oil fields are reflected in the development of the model allowing the effect of each scale on the others to be taken into account. The new model has been applied to investigate the potential scale precipitation in Iranian oilfields, either in onshore or offshore fields where water injection is being performed for desalting units' water disposal purpose or as a method of secondary recovery or reservoir pressure maintenance. Introduction Scale formation in surface and subsurface oil and gas production equipment has been recognised to be a major operational problem. It has been also recognised as a major causes of formation damage either in injection or producing wells. Scale contributes to equipment wear and corrosion and flow restriction, thus resulting in a decrease in oil and gas production. Experience in the oil industry has indicated that many oil wells have suffered flow restriction because of scale deposition within the oil -producing formation matrix and the downhole equipment, generally in primary, secondary and tertiary oil recovery operation as well as scale deposits in the surface production equipment. Oil field scales costs are high because of drastic oil and gas production decline, frequently pulling of downhole equipment for replacement, reperforation of the producing intervals, reaming redrilling of the plugged oil wells, stimulation of the plugged oil-bearing formation, and other remedial workovers. As scale deposits around the wellbore, the porous media of formation becomes plugged and may be rendered impermeable to any fluids. Many case histories [14,15,21,23–26,28,29,32,34–41,44–47] of oil well scaling by calcium carbonate, calcium sulphate, strontium sulphate and barium sulphate have been reported. Problems pertaining to oil well scaling in North Sea fields have been reported [24] and are similar to cases in the Russia where scale has severely plugged wells. Oilfields scale problems have occurred as a result of water flooding in Algeria, Indonesia in south Sumatra oilfields, Saudi oil fields and Egypt in El-Morgan oilfield [12] where calcium and strontium sulphate scales have been found in surface and subsurface production equipment. This study investigated scale formation and deposition in Iranian oilfields.

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Loading up of liquids in wellbore has been recognized as one of the severe problems in gas production for many years. Accurate prediction of the problem is vitally important for taking timely measures to solve the problem. Although previous investigators have suggested several methods to predict the problem, results from these methods often show discrepancies. Also, these methods are not easy to use because of the difficulties with prediction of bottomhole pressure in multiphase flow. An accurate and easy-touse method is highly desirable. This paper fills the gap.Starting from Turner's analysis for prediction of the minimum gas velocity for liquid removal, the minimum kinetic energy of gas that is required to lift liquid droplets was determined in this study. In order to compare gas kinetic energy with the minimum required kinetic energy, a four-phase (gas, oil, water, and solid particles) flow model was developed for mist flow. Applying the minimum kinetic energy criterion to the four-phase flow model resulted in a closed-form analytical equation for predicting the minimum gasflow rate.The kinetic energy theory indicates that the controlling conditions for liquid drop removal in gas wells are bottomhole conditions rather than tophole conditions. Our case studies show that Turner's method with 20% adjustment still underestimates the minimum gas velocity for liquid removal, and the newly developed equation is more accurate than Turner's method. The new method is easier to use than other existing methods. This paper provides production engineers with a systematic approach to predicting the minimum gas-production rate for the continuous removal of water and oil from gas wells. Engineering charts are provided for two typical tubing sizes and wellhead pressures.

Production enhancement and ultimate recovery improvement have given horizontal wells the edge over vertical wells in many marginal reservoirs. However, it is more expensive to drill and complete a horizontal well than a vertical one. Therefore, to determine the economical feasibility of drilling a horizontal well, engineers need reliable methods to estimate its productivity.After a broad literature review, a simple semianalytical model has been developed in this study for predicting the productivity of horizontal oil wells. This model couples flow from a box-shaped drainage volume to flow in the wellbore. Along with friction, acceleration, and fluid-inflow effect, change in flow regime from laminar to turbulent is also taken into account to describe flow in the wellbore. The reservoir-inflow model used in this productivity model represents flow in the reservoir using a combination of 1D and 2D models and also considers varying skin along the wellbore to account for the heterogeneity of the near-wellbore region because of drilling-fluid invasion into the formation. In addition, reservoir-permeability anisotropy and convergence of flow to the wellbore have been taken into account in this inflow model. Comparison of this model with three existing models using field data reveals that the proposed model is more accurate because of more-realistic modeling of reservoir inflow and wellbore flow.The semianalytical nature of this coupling model makes it comprehensive and applicable to reservoirs with varying conditions, especially heterogeneous reservoirs. Moreover, this productivity model can be extended easily to estimate the deliverability of multilateral wells by coupling the inflow performance of individual laterals with hydraulics in buildup sections and the main vertical section. A logical procedure for calculating the deliverability of multilateral wells by using this productivity model is described in this paper.

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