Abstract

Production increases of 50 to 100% and more have been Production increases of 50 to 100% and more have been obtained with plunger lift installations on gas wells in the South Burns Chapel Field in northern West Virginia. At the present time, 14 wells out of 35 are being produced with plunger lift. Pre-installation analysis produced with plunger lift. Pre-installation analysis showed that gas/liquid ratios (GLR) were high indicating potential success, but significant downtime was recorded during the initial phases of production. An operations guideline for plunger lift installation and startup has been developed to reduce downtime on future installations.

Introduction

Phillips Petroleum Company developed South Burns Phillips Petroleum Company developed South Burns Chapel Field in the mid to late 1960's. The wells are drilled to approximately 8000 ft [2440 m] and completed in the naturally fractured Onondaga Chert and Oriskany Sandstone. Natural flow and formation permeability are low, but after stimulation, initial production rates range from 500 Mcfd to 2000 Mcfd [14,150 m3/d to 56,630 m3/d]. By the mid 1970's, production rates had declined and many of the wells were experiencing periodic loading up with formation water. In general, the wells were blown down to unload liquid slugs and then produced at a moderate choke setting until they loaded produced at a moderate choke setting until they loaded up again. The cycle of blowdowns followed with production is not entirely efficient. It is doubtful production is not entirely efficient. It is doubtful that the wells were unloading all formation water or producing at full capacity. Plunger lift was considered at the time, but was rejected due to partner objections. Other alternatives, such as partner objections. Other alternatives, such as lowering wellhead pressure with compression, soapsticks, other chemical foamers, and swabbing were rejected for economic and operational reasons.

By the mid 1980's, the situation had become acute. Many of the wells required more frequent blow-downs and the actual production cycles were becoming shorter. The situation was worsened by the loss of a saltwater disposal (SWD) source in 1985. Alternative SWD sources were uneconomical, so the wells were allowed to produce through the tubing-casing annulus, thereby guaranteeing that no water would be produced. In 1987, a reliable and economic SWD source was located and it was decided to produce the wells through the tubing in order to unload formation water and increase production. Wells producing at rates greater than production. Wells producing at rates greater than 70 Mcfd (1980 m3/d) responded with a noticeable rise in production. However, lower flowrates in other wells did not provide the gas velocity necessary for the removal of formation water. Plunger lift was again considered to Plunger lift was again considered to alleviate loading problems.

APPLICATION DESIGN

Several publications document the design and application of plunger systems in oil and gas wells. Basically, plunger lift is a form of artificial lift that uses a traveling piston or plunger to remove liquids from the wellbore. It efficiently uses the energy from expanding gas to keep oil and gas wells from loading up. The efficiency of the plunger is derived from the solid interface it forms between the liquid slug and expanding gas underneath. A plunger traveling up the tubing forms a dynamic plunger traveling up the tubing forms a dynamic seal between itself and the tubing walls, thereby preventing liquid fallback. preventing liquid fallback. The requirements for operation are customarily stated in terms of a minimum GLR necessary to cycle the plunger. Tables and curves identifying the minimum gas requirements are available.

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