A new, fully automated completion system contributed to improved safety and efficiency of plug and perforate completions on 34 horizontal wells completed in west Texas Delaware Basin between 2018 and 2020. By enabling nearly continuous frac operations and wireline transitions in three minutes or less, the new system helped reduce the average time-to-complete a well by 38% compared to the average performance on the operator's nearby wells completed using a traditional latch.
Primary barriers to fracturing the reservoir 24/7 have been identified as 1) the time between stages (this includes transition time and pressure tests), 2) downtime associated with gate valve maintenance and failures, 3) frac pump maintenance and 4) sand and water logistics. Following a prescribed roadmap, a system has been developed with new subsystems and processes to eliminate these identified barriers through novel products and automated workflows resulting in fracturing the reservoir more hours per day with the goal of reaching 24 hours a day, 7 days a week (please note the difference between being on a frac site 24/7, which occurs today, and fracturing the reservoir 24/7). The system eliminates the time between stages with rapid, automated transitions from one stage to the next enabling operators to continuously pump for the duration of the completion. Utilizing automated workflows, interlocks with wireline and frac systems, control systems, and RFID, the system eliminates NPT associated with stage-to-stage transitions. An addition to the system that enables the exchange of pumps during frac operations without stopping the frac has gone through initial field trials, with a second iteration soon to be deployed. Although the overall system does not directly solve logistic issues (i.e. sand and water shortages), the demonstrated consistency achieved using the system enables better planning of resources. A summary of the system’s accomplishments, some previously disclosed, some new, will be presented. The system has broken multiple pumping records across US basins including hours pumped continuously and stages completed. In addition, the system has over a dozen industry "firsts" that have advanced completion practices, reduced NPT, and eliminated transition time. The paper highlights new additions to the system including the automated lubricator, automated greasing algorithms, and the ability to exchange a pump truck while fracturing. Utilizing the plentiful data provided by the system, specific case histories are documented highlighting the gains in operational efficiency, consistency and safety resulting from the new system.
The capabilities of permanently installed fiber optic cable to monitor the distribution of slurry between perforation clusters in a hydraulic fracturing treatment are now well understood throughout the industry. The distributed measurements from the fiber optic cable gives the ability to test different completion designs to evaluate which design can promote a more uniform flow distribution between perforation clusters. Over the past few years, the cost of utilizing a permanently installed fiber optic cable has decreased. However, the investment still adds to the total development cost of the pad, meaning that the knowledge gained from fiber optic measurements need to be maximized in order to realize the value added and to lower costs on future developments. For this reason, it is imperative to understand the challenges to be solved by implementing this technology, and to create a structured design of experiments suited to solve these challenges. This paper presents some recent work performed in the southern Delaware Basin utilizing fiber optic-based distributed acoustic sensing data. The primary objectives of this project were to improve the fluid distribution between clusters and to test the ability to keep the improved fluid distribution while extending the treatment interval length. The variables changed between experiments to achieve these goals will be discussed along with their corresponding results. It will be shown how pairing the fiber optic measurements with a structured design of experiments increased the knowledge gained from the fiber optic project.
Summary Development of hard-to-recover reserves in Russia necessitates the development of new technologies and use of those technologies for efficient production of hydrocarbons. One such technology is multistage fracturing in horizontal wells. Beginning in 2010, such technologies have been widely used in many regions. A liner with swellable or hydraulic packers for separation of intervals and fracture ports opened with balls or actuated with the help of coiled tubing is the simplest and most economically effective method for completion of horizontal sections of boreholes. Well production using multistage fracturing helps maximize initial flow rates and hydrocarbon extraction; however, production declines over time can be significant and, in some cases, it is necessary to perform repeated reservoir stimulation treatments to maintain an economic production level. Refracturing wells with shifting sleeves is complicated because it is necessary to perform selective interval isolation for the target interval treatment. Mechanical isolation involves special tools for well treatment and fracturing, which significantly increases the cost and duration of treatment. Multistage fracturing fluid diversion, with the help of biodegradable diverting agents, is widely used in unconventional reservoirs but has not been used effectively in reservoirs with relatively high permeability. The method discussed in this work is based on injection of a degradable diverting agent, sealing of highly permeable intervals, recovery of permeability of existing fractures, and formation of new hydraulic fractures. This technology does not require any special tools and substantially reduces treatment time. However, such specific technology requires adjustment and calibration to particular formation conditions and completion types. This paper describes the flow diversion multistage refracturing technology tested at Las-Eganskoye field. The technology was tested in formations with relatively high permeability. Results of well treatment and testing allowed for assessing key process procedures and developing measures aimed at adjusting the method to field conditions.
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