Increasing the Time between Failures of Electric Submersible Pumps for Oil Production with High Content of Mechanical Impurities

The main principles of hydroabrasive wear of parts of the pumping stages of well’s electric submersible pumps are considered in this article. The concentration, grain-size distribution and shape of solid particles have the greatest impact on the abrasion ability of particles of mechanical impurities interacting with the parts of pumping equipment. The implementation of filters is the most effective and affordable way to protect borehole electric submersible pumps from hydroabrasive wear. Filters reduce the concentration and decrease the average grain-size of mechanical impurities going through the pumping stages. The authors propose variants of constructive and schematic solutions of self-cleaning slot filters, providing an increase in the operating time of electric centrifugal pump units during production of well fluid with a high content of mechanical impurities. The operating principle of the proposed filters is described. The results of calculations of deformation of tubing string during the increase in pressure at the oil wellhead are presented, confirming the possibility of restoring the permeability of spring filter elements without lifting the pump unit to the surface.

Concentric Coiled Tubing, Proven Sand Cleanout Technology for Sub-Hydrostatic Wells in Caspian Sea

Index of sand production is one of the major issues faced in oil and gas wells on the Caspian region. Although there are multiple technologies to address this issue, the application of these technologies require the well to be cleaned before proceeding with any kind of remedial application. Concentric Coiled Tubing (CCT) sand vacuuming technology has brought a massive advantage for efficiently cleaning the wellbore of sub-hydrostatic wells in Caspian Sea. CCT system is the Coiled tubing string inside of Coiled tubing string which essentially provides a smaller second annular return route for the wellbore solids while simultaneously boosting the return pressure and allowing us to clean the sand where the bottomhole pressure (BHP) is low and not enough to support the circulation of fluids used for the cleanout. Cleanout fluid is pumped through the inner string to power the downhole jet pump comprised in CCT bottomhole assembly (BHA) which creates a drawdown that vacuums the solids and circulates the solids back to surface via the CCT annulus. The solid performance of the CCT system has an established track record worldwide and application of this sand cleanout technology brought a solution for recovering many wells with low BHP and has been successfully implemented since 2013, providing a method for cleaning out tons of accumulated sand particles from challenging wells in Caspian Region. With the complex system being used for cleaning out sand and also surface handling of the solids in the return flow from the wellbore, CCT sand vacuuming technology has proven to be effectively functioning in all cases that it was selected for so far. This Paper reviews the design and mechanism of the CCT sand/well vacuuming system as well as the results of several well intervention cases with its successful execution and lessons learned in Caspian region.

Optimized Coiled Tubing Approach in Offshore Multi-Stage Hydraulic Fracturing Project

Operator at the Russian segment of the Caspian sea offshore, engineered a project to drill and complete four experimental horizontal extended reach wells with very aggressive trajectories, into tight Oil & Gas bearing formations with further mission to complete them with multiple hydraulic fracturing. This resulted in a selection of complex completion design with multiple shifting sleeves to allow efficient multistage frac treatment and subsequent production of each zone. Technical challenge of the project was to deliver enough force into shifting sleeves to manipulate them with close-open-close cycle, in a horizontal extended reach wellbore with average 2800mMD (1900mTVD) with anticipated excessive proppant accumulation after each treatment, and it was expected to further restrict the required force delivery in extended reach wellbore. Challenges were addressed during well design stage, by using a proprietary engineering simulation software to analyze the large spectrum of the Coiled tubing string with different mechanical properties. Additionally, feasibility study, considered the application of downhole aids to overcome wellbore cleanout issues, helical buckling and friction lock-up, to deliver required force to the shifting devices. A critical part for the effective delivery of the operations was the time spent designing each intervention individually. Having the expertise to perform proper project management, provided the opportunity to identify several potential challenges that could appear during the campaign. Numerous simulations of tubing force analysis were performed, considering different string configurations, in the intent of overcoming the difficulties resulting from the unconventional trajectories of the wells. One important selection made, was the extended reach auxiliary options, which could aid in reaching the target depths with enough WoB to shift the sleeves. The feasibility study also included extensive simulations on options to remove solids from the wellbore on an efficient manner This paper details out the design specification of the Coiled Tubing technologies selected for the projects as well as address the engineering and operational challenges and solutions proposed to deliver the successful offshore campaign. First time use of the large 2 5/8" OD coiled Tubing string in Offshore Caspian sea and related operational and logistical challenges are the novelties discussed in this paper. Paper also highlights the operation sequence and success of the selected pipe design and downhole approach.

Technology for Preventing the Wax Deposit Formation in Gas-Lift Wells at Offshore Oil and Gas Fields in Vietnam

Within the past few decades, the production of high-wax oils at offshore fields in Vietnam has been fraught with severe problems due to the intense formation of asphalt-resin-paraffin deposits (ARPD) in the downhole oil and gas equipment. The formation of organic wax deposits in the tubing string led to a significant decrease in gas-lift wells production, efficiency of compressor units, transport capacity of the piping systems, along with an increase in equipment failure. Subsequently, the efficiency of gas-lift wells dramatically decreased to less than 40% as a whole. The existing methods and technologies for combating organic wax deposit formation in downhole equipment have many advantages. However, their use in producing high-wax anomalous oil does not entirely prevent the wax formation in the tubing string and leads to a significant reduction in oil production, transport capacity, and treatment intervals. The results of theoretical and experimental studies presented in this article demonstrate that a promising approach to improve the efficiency of gas-lift wells during the production of high-wax oil is to use the technology of periodic injection of hot associated petroleum gas (APG) into the annulus of an oil-producing well. The effectiveness of the proposed method of combating wax formation in gas-lift wells highly depends on the combination of a few factors: the determination of wax deposit formation intensity in the well and the implementation of a set of preparatory measures to determine the optimal injection mode of hot APG (flow rate and injection depth) into the annulus between tubing strings and technological pipes. The injection depth of the hot APG should not be less than the depth of wax formation in the tubing string. The optimal injection rate of hot APG is determined by analyzing and mathematically modeling the APG injection system based on well-known thermodynamic laws.

Failure Analysis of Cracked and Corroded Tubings in Sudong Block of Changqing Oilfield

In the process of layer inspection and hole mending, it was found that the corrosion of tubing in a well was serious, and perforation and fracture occurred. Part of the tubing was found to be cracked from the failed pipe samples, and relatively serious pitting corrosion pits were found on the surface of the outer wall. The fracture morphology and corrosion products were analyzed by means of macroscopic analysis and metallographic microscope, SEM and EDS. The result show that the mechanical damage of the outer wall of the tubing was the primary condition for accelerating corrosion, and the severe corrosion thinning of the inner and outer walls of the tubing was the main reason for the failure of the tubing string. The corrosion perforation of tubing was mainly caused by internal corrosion.

Packer-Setting Methodology with Auto-Fill Capability and Interventionless Valve Reduces Completion Cost

A new valve has been designed and qualified to reduce interventions during packer-setting operations. In a typical well, completion with a hydraulic-production packer, the tubing string must be plugged to create the required pressure differential for packer actuation. At desired depth, delivering a preselected circulation rate actuates the tool and converts the string to a closed system, enabling the packer to be set hydraulically. Before designing the valve, an operator's engineering and operational requirements were collected and understood. Then a conceptual design was evaluated, and a prototype device was manufactured. The valve was tested for autofill capability, actuation parameters and pressure integrity. The critical design elements of the valve are the choking and spring mechanisms, which enable circulation without prematurely actuating the valve and then enable tubing autofill. A visual inspection post qualification test was conducted to validate the components’ condition and integrity. During the qualification process, the valve working envelope was developed. After the successful qualification test, the valve was deployed in a customer well with a production packer that has a blanking device consisting of a ceramic disc. Prior to deployment, hydraulic simulation was done to determine the required flow rate to achieve desired pressure drop across the valve for actuation. During deployment, the tubing was filled automatically, validating the valve autofill capability. Upon reaching setting depth, the completion string was circulated at the required circulation rate to actuate the valve and close the system. Pressure integrity in the tubing validated the valve functionality. Surface pressure was applied against the blanking device, and the production packer was set hydraulically. Subsequently, before completing the well, the blanking device was broken using a slickline run, and the well was put on production. The deployment technique using the valve requires only one slickline run whereby in typical operation four slickline runs are required. This project represented true problem-solving engineering approaches. The operator requirements were properly understood and conceptual design was validated, and product realization phase was initiated. The efficient product development methodology improves the lead time from conceptualization to product realization. During the first well deployment, hydraulic simulation during the prejob planning proved to be critical to understanding the required circulation rates to actuate the valve.