A frozen consolidated formation that is. unharmed by thawing probably can be cemented with any slurry that will adequately set at the existing curing temperature. In area where the frozen formations contain ice lenses and are incompetentwhere the formation must not be allowed to thawspecialized slurries must be called upon to do the job. Introduction Increasing oil industry activity in the nothern areas of Canada, the Arctic Islands, and the State of Alaska has focused attention on the special problems of cementing conductor and surface casing in cold and frozen formations. With an understanding and proper application of the relationships among the performance of available materials formation and well fluid temperatures, mixing water and cement slurry temperatures, and the cement heat of hydration, the present-day practice of adhering to a 24-hour present-day practice of adhering to a 24-hour waiting on-cement (WOC) time can be modified so that the WOC is as short as 8 hours. Cementing through the permafrost of the more northern regions presents a new set of difficulties. Cementing techniques and materials depend mainly upon the type of permafrost. A frozen consolidated formation that is unharmed by thawing probably can be cemented with any slurry that will adequately set at the existing curing temperature. In areas where the frozen formations contain ice lenses and are incompetent - where the formation must not be allowed to thaw - specialized slurries must be used. Cementing Through Nonfrozen Formations Strength of Cement Accepted practice of the industry in cold formations has been to place cement behind conductor or surface pipe and wait 24 hours. Investigators recognized pipe and wait 24 hours. Investigators recognized many years ago that very little strength was needed to support casing and drillpipe in the borehole (Table 1). Because of variations in procedures, materials, and curing temperatures, conditions cannot be sufficiently known in the field to establish the curing time required to obtain this minimum strength, thus a safety factor should be applied. A compressive strength of 500 psi is generally accepted as adequate for most operations, and with diligent practice an operator should be able to drill out safely practice an operator should be able to drill out safely using an established minimum strength of 250 psi. The curing time (WOC) for cement to develop the minimum required strength can be shortened by reducing the volume of mixing water (densification), by adding an accelerator, or by combining densification and acceleration. This is illustrated in Figs. 1 and 2, which show that curing temperature is a significant factor in strength development. To establish a sensible WOC time some knowledge of curing temperature must be gained. Static bottom-hole temperatures in western Canada 5 and other areas have been reasonably well defined by application of surface isotherm data coupled with depth-temperature gradients. However, the curing temperature of the cement will not equal the formation temperature and it does not even have a constant value. It is governed by a complex set of variables that includes the temperature of the drilling mud, cement slurry, and displacement fluid, as well as the heat of hydration of the cement. JPT P. 1215

The waiting-on-cement time in low-temperature surface casing cementing canvery often be reduced to less than what is common practice today through abetter understanding of cementing conditions. Two major factors in the earlydevelopment of the compressive strength of cement are the water-cement ratioand the curing temperature. The latter is partially dependent upon theformer. The strengths of cements required for drill-out are discussed, and the curing times required to achieve the necessary strengths are presentedgraphically. API Class A, B and C cements are considered, and the advantages of using the densified systems are illustrated. Data from field studies concluded over the past several years, including temperature measurements on well fluids and temperature surveys followingcement jobs, illustrate the curing temperature behaviours of typical western Canadian surface casing cement jobs. The effects caused by heat of hydrationand by cement mixing water and displacement fluids which are warmer than formation temperatures, can be rather significant, producing average curing temperatures which are higher than the surrounding formation temperatures by asmuch as 5°F to 30°F or more. A laboratory study was made to determine the comparative effects of the heatof hydration of cement slurries under different conditions. The heat evolved isincreased when (1) the slurry is placed at a higher starting temperature, (2)the volume of slurry is increased and (3) the slurry is mixed at a higherdensity. Cementing practices are discussed and recommendations made. With a more thorough knowledge of the basic factors involved, it should be possible in manycases, to more accurately correlate the required waiting-on-cement time withthe conditions as they exist rather than adopt a policy of fixed time which satisfies all probable conditions of cementing materials, temperatures and techniques. Introduction The phrase "waiting-on-cement," or "WOC," has long been a misnomer in mostinstances. The nonproductive and expensive time spent waiting has usually notbeen necessary, because, in fact, the cement was firmly set and was actuallywaiting on us. Increasing concern is being expressed by the industry over thiscostly waste, and continual attempts are being made to reduce WOC time to asafe minimum. The area of greatest interest appears to be that of surfacecasing cementing; this is due to the difficulties caused by the lowertemperature curing conditions.

A tool designed for formation sampling during drilling has been placed in Canadian field operations for over two years. Relatively large fluid samples are recovered and a formation pressure build-up obtained without retrieving the drill pipe. This paper discusses the mechanical operation of the tool as well as the characteristics of sample recoveries and pressure data. Typical examples are given.Qualitative reservoir information may be obtained to assist the operator in further evaluation and completion operations. Special applications include aid in the location of gas-oil and oil-water contacts, the calculation of potentiometric surfaces and the determination of reservoir continuity or segregation. An economic comparison with conventional drill-stem testing is made to illustrate the possible extent of savings. A summary of operations is given, describing the tool's performance and the results achieved.

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