As the oil industry begins to emerge from one of the worst downturns in decades, companies need to operate in a market of unstable oil prices that the upstream oil and gas industry continues to face. New innovative, sustainable, and disruptive artificial lift technologies are the cost-effective way seek by the operators to minimize risks, maximize production, and remain profitable on the market. In wells with sucker rod-lift systems, elastic beam vibrations induced by downhole pump operation are the main source for premature rod string failure and tubing wear. A completely new steady-state vibrations model for rod string assemblies has been implemented to understand and predict the rod/tubing wear damage phenomenon responsible for half of all well failure events in beam pump operation and most expensive routine well servicing cost. This paper introduces the developed model to enhance prediction of mechanical rod string dynamics during pumping operation, and delivers next generation analytics solution to be utilized for artificial intelligence, industrial internet of things, real-time monitoring, and automation of rod pumping systems. The model works on a set of forced Duffing-like differential equations with cubic non-linearity and damping, these generated discretizing beam elastic behavior using vibration mode basis. Model simulation runs in the time domain numerically capture relevant axial-flexural dynamic forces undergone by rod string during up and down stroke phases, as well as downstroke rod string bending-buckling tendency and its interaction with tubing internal wall. Some examples show usefulness of the novel model to predict failures and maximize uptime, reduce costs with predictive analytics, and design the optimal rod lift solution in every stage of well life cycle.

Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology designed specifically for natural gas wells and will serve an as yet unrealised opportunity within the Upstream Gas industry. The technology offers the opportunity to increase production by 30–50%, significantly improve reserves and delay the onset of liquid loading. Although it can be applied at any time during a gas asset's life cycle, it will find particular favour during the decline phase. It may also be used to extend the life of a field hence delaying divestiture. While DGC has clear parallels with Electrical Submersible Pumps (ESPs), its deployment into gas wells presents new challenges due to the incompatibility of current well control methods and the technologies and operational considerations necessary for efficient wellbore turbo-compression. This paper presents these issues and reports on the candidate well selection criteria, the compressor requirements and the well completion design for the world's first DGC installation in a live gas well to be conducted by Eni in an operated mature gas asset located in Southern Italy. The paper offers guidance to other operators on the design, installation and operational considerations for the deployment of this all new Artificial Lifting System for gas wells. Introduction The Upstream Gas Industry is often faced with the challenge of selecting an optimum Artificial Lifting system for a well from various alternatives available for gas well production enhancement. These challenges become more complex with increasing dynamic changes in well flow characteristics over the life of the well. Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology designed to serve an as yet unrealised opportunity within the natural gas extraction industry. The new technology comes at a crucial time for the global energy market. As previously reported (OTC 16372 and SPE 96037) the application of DGC technology in suitable wells offers value for:Acceleration of early production and extension of production plateau in new gas developments;Cost effective rejuvenation of mature gas reservoirs characterized by low reservoir pressure and liquid accumulation into the wells;Improvement of gas well production and maximization of recovery factor from gas reservoirs with low environment impact;Identification of incremental reserves and for monetizing stranded gas. As part of an ongoing development through a Joint Industry Program (JIP) supported by Corac, Eni, ConocoPhillips, and Repsol-YPF; Eni is to conduct the first field trial of the new technology in an onshore gas well producing in an operated mature asset located in Southern Italy. The Programme has been completed in phases including the design, build and testing in a full scale flow loop closely replicating downhole conditions (SPE 116406). The prototype has been tailored to suit the expected gas flow range, composition and condition of the selected field trial well.