The Effects Of Pressure On The Set Properties Of Cements With Various Additives
Authors: Metcalf Arthur S. 
Published: December 2007

Limited information is available on the effects of pressure on the set properties of cements with respect to commonly used additives. This report presents compressive strength data on cement systems presents compressive strength data on cement systems cured at temperatures of 170 degrees to 260 degrees F and at pressures of 3,000 to 10,200 psi. Of the cement systems studied, those designed for a specific bottom hole static temperature (BHST) show little change in compressive strength with increased curing pressure at BHST. However, some systems, cured at pressure at BHST. However, some systems, cured at temperatures lower than BHST, gave increased or decreased compressive strength with increased curing pressure. The use of curing pressures simulating more closely those actually found in oil or gas wells gives a better understanding of additive performances and a more realistic waiting on cement (WOC) time for cement systems.

Introduction

Several authors have shown that the effects of curing pressure above 2,000 psi are negligible on the development of 24-hour compressive strengths on neat cements at a curing temperature of 200 degrees F. However, the development of 12-hour compressive strengths on oil and gas well cement systems of varying retarder content, cured at different bottom hole circulating temperatures (BHCT), has been shown to increase with increased curing pressure.

No other, or only limited information, is available concerning the effects of curing pressure on the development of compressive strength on cement systems with respect to various additives and combinations of additives. Today in numerous wells, cement systems are placed under varying pressures in excess of 3,000 psi. Therefore, in order to improve the design of cement systems for these wells, an understanding based on experimentation of the effects of these higher curing pressures on the performance of additives is needed. performance of additives is needed. This paper examines the effects of curing pressures of 3,000 psi to 10,200 psi on the 8, 12 pressures of 3,000 psi to 10,200 psi on the 8, 12 and 24-hour compressive strengths of cement system with various additives, cured at 170 degrees to 260 degrees F. The main purpose of this work is to study the compressive strengths of cement systems at temperatures and pressures that could exist at the top and bottom of a cement column under simulated well conditions.

Discussion

The number of various types of additives used in any given cement job is directly related to the depth, temperature, and type of formation encountered in an oil or gas well. With the large variety of additives in existence and the wide range of well conditions possible, some limitations had to be imposed on what was to be studied in this preliminary investigation. The cements examined were preliminary investigation. The cements examined were limited to a class H, class G and a 50:50 fly ash: class H. The additives examined were limited to a lignosulfonate retarder, a cellulose fluid loss additive, bentonite, and salt. The well conditions under which samples were cured were based mostly on those possible in a 12,000 ft. well.

The specific cement systems examined are listed in Table I with the mix water, density, and thickening times. All the cement systems containing additives, except the salt systems, were designed for placement in a 12,000 ft well with a BHST of 260 degrees F. These systems all had 4–6 hours thickening time at a BHCT of 197 degrees F. The systems were all cured at 170 degrees, 200 degrees, 230 degrees, and 260 degrees F under various pressures for 24-hour compressive strength determinations with the lower temperatures used to simulate the tops of various length liner cement jobs. The salt systems were examined only at 170 degrees F because this was representative of a temperature at which salt may be used alone.

The 30 degrees F intervals in curing temperatures constitute 2,000 ft depth changes in wells with a 1.5 degrees F/100 ft depth temperature gradient.