Abstract

Casing vapor production is the result of steam injection being greater than the sum of necessary process heat and heat losses in the reservoir. During the development of heavy oil steamfloods in the Kern River Field in the 1970's, a system was installed to collect casing vapor from producing wells and condense it on the surface. Casing vapor production reduces the pressure in the wellbore increases the pressure gradient from the reservoir and increases oil production rate. A study was undertaken to evaluate the effect on oil rate of shutting in the production of casing vapor.

In November, 1994, casing vapor production was shut-in on a 128 well pilot study. Baseline (preshut-in) and pilot (postshut-in) data was analyzed for the next 16 months. An oil production rate drop was expected and experienced in the pilot as a result of reducing the pressure gradient, thus changing the relative impact of producing mechanisms in the reservoir. There were no sustained production effects observed from casing vapor shut-in after 16 months of data analysis following shut-in. In that time, the pilot had produced the same cumulative oil as predicted by established preshut-in production decline.

Based on the pilot data, large scale casing vapor recovery closures have begun in the Kern River Field. Mitigation testing in the pilot indicated the field shut-in would not be as negatively impacted. The same cumulative oil production, with the benefit of eliminating casing vapor recovery system costs and utilizing the excess heat in new projects all lead to improved economics and increased ultimate recovery in the Kern River Field.

Introduction

The Kern River Field is a large, shallow, heavy oil reservoir located northeast of Bakersfield, California. Both reservoir and fluid characteristics are very favorable for thermal recovery methods. The reservoir consists of an alternating sequence of unconsolidated sands with considerable interbedded silts and clays. The sands range in thickness from 25 to 150 feet and exhibit high permeabilities of 1 – 5 darcies and porosities of 28 – 33%. Reservoir pressure is low, averaging 50 psig. Oil viscosities, which average 4,000 cp at initial reservoir temperature, are very effectively reduced by steamflooding.

During the mature stages of a steamflood, the oil region is entirely overlain by a steam zone, Figure 1. The steamflood process may be supported by steam condensation at the steam/liquid interface in the advanced rate of heat transfer provided by advection and by hydrocarbon condensing along the steam/liquid interface providing some light end upgrading to the oil. Steam injected beyond this minimum required process heat and reservoir cap rock heat losses continues through the reservoir to be produced in the annulus of producing wells. In the early practice of steam flooding, little consideration was given to the amount of heat necessary to drive the process, but rather to the relief of the producing well annulus pressure to maximize the pressure difference between the reservoir and the well, thus maximizing inflow. Producing well casing valves were open to atmosphere to relieve the annular pressure, resulting in significant volumes of steam vapor blowing from the annulus of producing wellbores. With the increased importance of environmental concerns these vapors were later collected in a surface casing vapor recovery system and cooled to collect the hydrocarbon condensate. Thus, steam was injected at rates far higher than required for maximum thermal efficiency.

Texaco's operation was recently faced with the problem of a vapor collection system that was approaching the end of its useful life. It became an economic decision whether to repair, replace, or eliminate the system.

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