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Electrical submersible pumps focuses on the standard ESP configuration. It has the pump, seal chamber section, and motor attached to the production tubing, in this order from top down. In some wellbore completions and unique ESP applications, the arrangement and configuration of the system is modified. For a bottom-intake design, the production fluid is drawn in the intake ports located at the very bottom of the ESP system and discharged out of ports located just below the connection to the seal-chamber section. Because the discharged production fluid cannot flow through the seal-chamber section and motor, it has to exit into the casing or liner annulus and flow past these units.
In practice, vapor/liquid reservoir phase behavior is calculated by an equation of state (EOS). The two most common EOSs that have been used for oil-recovery solvent-injection processes are the Peng-Robinson EOS and the Soave-Redlick-Kwong EOS. Of the two, the Peng-Robinson EOS seems to be the one most often cited in the literature and is the one discussed in some detail. The Soave-Redlick-Kwong EOS is used in a similar manner to predict solvent/oil phase behavior. For heavier components, where ω 0.49, the following equation is recommended: The constants in Eqs. 2 and 4 are often designated Ωa and Ωb. Eq. 1 represents continuous fluid behavior from the solvent to liquid state, and it can be rewritten as Jhaveri and Youngren adapted a procedure used by Peneloux et al. and modified the original Eq. 1 to include a third parameter to allow more-accurate volumetric predictions, which is recommended for solvent/oil simulations.
Before undertaking any type of compositional numerical simulation of a miscible flood, it is crucial to identify the phase behavior occurring in the reservoir. Phase diagrams are a typical method for representing phase behavior. Ternary diagrams and pseudoternary diagrams have been used for decades to visualize conceptually the phase behavior of injection-fluid/crude-oil systems. This is done by representing multicomponent fluids or mixtures by three pseudocomponents and then plotting fluid compositions in the interior of an equilateral triangle with apexes that represent 100% of each pseudocomponent and where the side opposite an apex represents 0% of that pseudocomponent. For example, the low-molecular-weight fraction might include methane and nitrogen and perhaps CO2 if CO2 is the primary injection solvent.
A "well test" is simply a period of time during which the production of the well is measured, either at the well head with portable well test equipment, or in a production facility. Most well tests consist of changing the rate, and observing the change in pressure caused by this change in rate. To perform a well test successfully one must be able to measure the time, the rate, the pressure, and control the rate. A Flow test is an operation on a well designed to demonstrate the existence of moveable petroleum in a reservoir by establishing flow to the surface and/or to provide an indication of the potential productivity of that reservoir. Some flow tests, such as drill stem tests (DSTs), are performed in the open hole.
New Technique for Addressing SIMOPS Challenges During Installation of New Offshore Platform. Simultaneous Operations in Multi-Well Pad: a Cost Effective way of Drilling Multi Wells Pad and Deliver 8 Fracs a Day. The glossary is a living growing list of important E&P terms and require continual enhancements. If you would like to contribute to the glossary send an email to petrowiki(at)spe.org.
The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking.
Emulsions are always a drain on the operating budget. It is almost impossible to eliminate emulsions during crude production; however, emulsion problems can be reduced and optimized by following good operating practices. The following points should be included in operating practices. Chemical-Demulsifier Development Based on Critical-Electric-Field Measurements. Husveg, T., Bilstad, T., Guinee, P.G.A. et al. 2009 A Cyclone based Low Shear Valve for Enhanced Oil-Water Separation. Paper presented at the Offshore Technology Conference, Houston, Texas, USA, 4-7 May.
Demulsifier selection is still considered an art that improves with experience; however, there are methods now available to eliminate some of the uncertainties involved in demulsifier screening and selection. The properties of a good demulsifier were addressed previously. How to select the best demulsifier and to optimize its usage is addressed here. Demulsifier selection should be made with the emulsion-treatment system in mind. Some of the questions to be asked include the following.
Contamination of drilling fluids with drilled cuttings is an unavoidable consequence of successful drilling operations. If the drilling fluid does not carry cuttings and cavings to the surface, the rig either is not "making hole" or soon will be stuck in the hole it is making. The drill cuttings that are separated from the drilling fluid on the surface by the soldis control equipment and some quantity of unrecoverable or economically unwanted drilling fluid are a major source of drilling waste. Drilled and formation solids that are sized smaller than can be removed by the solids control equipment are often reported as drill solids. Some quantitiy of drill solids will accumulate in the drilling fluid and must be removed by the solids control equipment or reduced in concentration by dilution.
The purpose of the digital oilfield is to maximize oilfield recovery, eliminate non-productive time, and increase profitability through the design and deployment of integrated workflows. Digital oilfield workflows combine business process management with advanced information technology and engineering expertise to streamline and, in many cases, automate the execution of tasks performed by cross-functional teams. The term "digital oilfield" has been used to describe a wide variety of activities, and its definitions have encompassed an equally wide variety of tools, tasks, and disciplines. All of them attempt to describe various uses of advanced software and data analysis techniques to improve the profitability of oil & gas production operations. If one maps the challenges onto the themes, it becomes clear that digital oilfields are attempting to compensate for a higher complexity and cost of operations which must be performed by fewer, less experienced employees.