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A number of cementitious materials used for cementing wells do not fall into any specific API or ASTM classification.These materials include: Pozzolanic materials include any natural or industrial siliceous or silico-aluminous material, which will combine with lime in the presence of water at ordinary temperatures to produce strength-developing insoluble compounds similar to those formed from hydration of Portland cement. Typically, pozzolanic material is categorized as natural or artificial, and can be either processed or unprocessed. The most common sources of natural pozzolanic materials are volcanic materials and diatomaceous earth (DE). Artificial pozzolanic materials are produced by partially calcining natural materials such as clays, shales, and certain siliceous rocks, or are more usually obtained as an industrial byproduct. Pozzolanic oilwell cements are typically used to produce lightweight slurries.
Almost all drilling cements are made of Portland cement, a calcined (burned) blend of limestone and clay. A slurry of Portland cement in water is used in wells because it can be pumped easily and hardens readily, even under water. It is called Portland cement because its inventor, Joseph Aspdin, thought the solidified cement resembled stone quarried on the Isle of Portland off the coast of England. Portland cements can be modified easily, depending on the raw materials used and the process used to combine them. Proportioning of the raw materials is based on a series of simultaneous calculations that take into consideration the chemical composition of the raw materials and the type of cement to be produced: American Society for Testing and Materials (ASTM) Type I, II, III, or V white cement, or American Petroleum Institute (API) Class A, C, G, or H.  The basic raw materials used to manufacture Portland cements are limestone (calcium carbonate) and clay or shale.
Abstract For nearly two decades in the Appalachian Basin many hundreds of Type I/II lightweight cement slurries with reduced compressive strengths, and increased elasticity have been successfully applied to Devonian Shale wells. More recently, hundreds of reduced density slurries have been successfully pumped on surface and intermediate casing jobs. Despite this success, the majority of new cement bid requests in the Northeast Region and perhaps across the U.S. for that matter still specify API monogrammed cement. The reality for the Northeast U.S. is that no cement plant within 450 miles manufactures to the API specification, except LaFarge at their Joppa facility. Plants manufacturing to API specification turn out a product that may vary more greatly batch to batch than the Type I/II cements. So much for uniformity and consistency, the most valued advantages of API cement. The situation begs the question: Why are drilling engineers so reluctant to pump more cost saving Type I/II lightweight slurries if they meet the technical criteria and are clearly more cost effective? One reason may be regulatory; state oil & gas code books were written years ago specifying API cement and compressive strength requirements for many applications. Another is awareness, many State Oil & Gas Regulatory Agencies may not know about the recent advances in oilwell cements, nor the fact that API cement is not available in their area of responsibility. This paper will lay out the case for Type I/II lightweight cement slurries, how they have superior mechanical properties for long term zonal isolation, and some example applications best suited to them. Supporting technical data includes cost savings and case histories of some applications. Efforts to educate the state regulatory agencies along with an example of successful requests for variances will be presented. Introduction U.S. consumption of cement is at record levels. Combined with the economic boom in China, shipping and global tie-ups add to the U.S. supply side troubles1. According to a recent Portland Cement Association flash report record demand in the first quarter of 2005 has increased U.S. cement consumption by 7% over 2004 levels2. That has led to tight supplies in at least 23 states this summer. Cement inventory levels are at historic lows in the U.S. and imports are rising. There are plans to increase manufacturing capacity but new plants are not expected to help much in the short term. Oil well cement demand is up as well with the domestic rig count nearing 1,400 rigs. Oil well cement is but a tiny fracture of worldwide production. Based on 2002 numbers the supply of oil well cement was an estimated 2.5 million metric tons or 0.15% of the 1.6 billion metric ton output. U.S. domestic production of all cement types in 2004 was approximately 86 million tons. Add to that imports of another 25 million tons and you get 111 million tons available to market. Only 1.7 millions tons of that or 1.5% was used in U.S. oil & gas fields3. The current status of oil well cement suppliers domestically is bleak.There are no cement plants in the Appalachian area and the Michigan Basin manufacturing cement to API specifications, and therefore none has a license to carry the API monogram. A quick internet search3 of a list of API monogrammed cement manufacturers revealed the following: Only two cement plants in the United States, LaFarge Joppa at Grand Chain, Illinois and the Texas Lehigh facility at Buda, Texas are licensed to carry the API Class A monogram. There were a total of 21 plants listed, the rest international. Five companies were listed as API Class C manufacturers with the only U.S. entry being Texas Industries' plant at Midlothian, Texas. Not one U.S. plant was seen of the list of API Class G cement plants containing 48 international entries. Three showed up when searching the list of 20 entries for API Class H. They were LaFarge Joppa at Grand Chain, Illinois; Texas Lehigh in Buda, Texas; and Texas Industries in Midlothian, Texas. See Table 1 for more details on API domestic and international cement manufacturers.
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.
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.
The Effect of Low-Water-Loss Additives, Squeeze Pressure, and Formation Permeability on the Dehydration Pressure, and Formation Permeability on the Dehydration Rate of a Squeeze Cementing Slurry
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
In an effort to improve the success ratios of squeeze cement jobs, recent studies were made of the effects of fluid-loss control additives, differential pressures, formation permeability, and placement techniques on the performance of squeeze cement slurries. The studies showed that the rate of filter cake build-up is the most important factor to be considered in squeeze cementing. They further showed that this rate is a function of the variables listed and can be calculated by Darcy's equation for flow of liquids through a permeable media. Use of Darcy's equation showed that fluid-loss additives currently in use function by reducing the permeability of the filter cake. This slows down the rate at which filtrate can be forced through the filter cake and controls the dehydration rate of the slurry.
This paper presents data relating the effects of the various factors on the dehydration rate of the slurry, and shows how a knowledge of well conditions and mechanisms of filter cake build up, along with good control over slurry properties can provide an appreciable improvement in the success ratios of squeeze cementing operations.
Squeeze cementing is a remedial cementing technique which has always been difficult. Since the introduction of low-water-loss additives for cement; however, the success ratio has consistently increased. These additives have made possible many placement techniques which previously would have been impossible. An understanding of the factors which influence water loss and filter cake formation is a great aid in the selection of the optimum slurry properties and placement techniques.
In order to attain a successful squeeze job, it is necessary to properly place the cement slurry. The slurry consists of finely divided particles mixed with enough water to contact all of the particles. As the slurry is forced against a permeable formation, particles will be filtered out on the face of the formation to form a filter cake. In most squeeze jobs, it is desirable to form this filter cake--but it is necessary to control its growth rate.
ABSTRACT ABSTRACT Possible perforating damage to casing and cement in production zones has indicated the desirability of improving the casing-cementing materials. Problems generally encountered may be casing splitting and cement fracturing as a result of using either too large a charge of explosives or an excessive number of shots per interval. This paper presents a new type of cementing composition containing synthetic fibers which helps eliminate damage to either the casing or cement, minimizing channeling between zones. In addition, its properties should provide a more satisfactory cement in areas where high-pressure fracturing may create unduly high cement-sheath stresses. The importance of improving cementing characteristics to overcome the detrimental effects of perforating under some conditions is shown by laboratory data. Field case histories exist from several troublesome areas of the country to help establish the successful application of this material in decreasing damage to either casing or cement, and reducing communication between relatively close-spaced zones. INTRODUCTION As completion practices become more complex, the need for better cementing materials to withstand the forces created by either perforating or fracturing has become more and more evident. This is especially true in primary completions, because of the different formation conditions being encountered and the need to reduce remedial cementing operations. These problem conditions may range from extremely long producing intervals to close producing horizons where isolation between zones is essential to achievement of a successful cementing job. Most of the techniques recommended in the past to improve primary completions have dealt mainly with either displacement rates for better mud removal or methods to improve cement bonding by both mechanical and chemical means. These techniques should not be disregarded, because they are still highly important in designing well-completion programs. However, very little investigation has been made in the area of improving the mechanical properties of the set cement. The use of synthetic fibers1 in the cement is very unique, because it not only results in increased strength but also improves the resiliency characteristics of the cement. This allows higher stress levels to be imposed, because the fibers act as small reinforcing rods to transmit the load more evenly throughout the cement in the same manner that steel improves this property in concrete. Primary purpose of the fibers in a cementing composition is to increase the impact and shatter resistance of the set material when it is subjected to perforation, because the blast forces produce shock and vibration which may be capable of damaging the cement. Another situation where shock and vibration occur is during drilling operations, particularly on the bottom joints when drilling out the shoe. Therefore, the possibility of using fiber-reinforced cementing compositions to overcome these stresses may be highly desirable. An additional benefit of the fiber-reinforced cement results from the extremely high tensile yield strength of the fibers; and in most cases its elasticity returns the cement to its original shape, even though the compressive yield strength of the cement has been exceeded
The expansion of cement and the effect of various expansive aids upon oil well cementing compositions have been investigated to determine the amount of expansion feasible and to observe the stability of cements displaying increased expansion.
Linear expansion measurements of 1×1×10-in. cement specimens have revealed that admixtures - sodium sulfate, sodium chloride, possolan and combinations of these - will effectively increase the expansion of cement. Since sodium sulfate solutions have been known to be deleterious to fresh water cement slurries after having set, the addition of sodium sulfate to the cement at the time of mixing was not at first considered as a satisfactory and practical means of increasing cement expansion. Considerable expansion was realized with no visible sign of deterioration of the cement in a period of nine months.
Laboratory tests have shown that bonding of cement between concentric sections of pipe was considerably improved when expanding cements were used. Measurements of the thermal expansion of cement have been made and coefficients of expansion calculated for several temperatures. A moderate decrease in cement expansion was noted with an increase in curing pressure with time.
Since as early as 1920, numerous investigators have been searching for a means of counteracting the shrinkage of concrete that occurs when it loses moisture under dry curing conditions. For some applications such as pre-stressed concrete, improved bonding in confined spaces and for inducing tensile stress in restraining steel, it has been more desirable to develop an expansive cement designed to more than compensate for any potential shrinkage. Expansive cements have been reviewed by Lafuma1 who discussed the factors affecting volume changes in concrete and cited references to earlier work dealing with this problem.
More recently, the composition of expanding cements and the chemical reactions involved, particularly the role played by calcium sulfoaluminate admixtures and related compounds, have been studied by Klein and Troxell.2 The preparation of anhydrous calcium aluminosulfate to produce expanding cement was reported by them, and in subsequent work Halstead and Moore3 were able to determine the crystal structure of this compound. Typical compositions of these expansive cements and methods of manufacture are revealed in two recently issued patents.4,5
The mechanism by which expansion can occur in Portland cement concrete as a result of the development of pressure by salt crystals was described in a paper by Hansen.6 The physical properties of expansive cement were recently investigated by Monfore7 who states: "If the expansion can be controlled so that it takes place when the concrete has developed some strength but is still extensible, the concrete may accommodate the expansion with a minimum of cracking. Such a cement might be termed a usefully expansive cement. But if the expansion occurs after the concrete has lost extensibility and has become so brittle that it can no longer accommodate the expansion without serious cracking or disintegration, the cement is properly termed unsound."
The principal concern of this investigation has been to determine the effect of some expansive agents upon cementing compositions for use in oil and gas wells, predicated on the improved bonding of cement to both casing and formation. Although good placement techniques are of the utmost importance in accomplishing a satisfactory oil well cement job, there are occasions when under even the most ideal conditions microflow channels may result from pressure differential between completion and production fluids in the casing, or because of thermal changes during the setting of cement. In such instances there is a probability that fluid or gas migration in the pipe-formation annulus can be reduced by the use of an expanding cement.
With regard to oil well cement slurries, it has been determined that a slight expansion will occur when the cement is cured under moist conditions. These same slurries, if air cured, will exhibit shrinkage due to loss of moisture. Since cement slurries are not generally subjected to a drying environment under down-hole conditions, they consequently would be expected to expand. However, the degree of expansion will vary somewhat with various classes, brands or batches of cement due to differences in chemical compositions, particularly tricalcium aluminate content.
The results of steam injection for production stimulation have created an incentive among oil producers to increase their drilling activity into heavy oil deposits which generally are found at rather shallow depths.
The use of heat in some form has been tried for many years to stimulate oil production. In situ combustion, downhole heaters, hot fluid injection and now steam stimulation are all being used. The ability to drastically lower oil viscosity in place using one of these methods, thereby increasing production rates and recovering additional oil, has brought about salvation for many low gravity crude producers in many fields. Heat is energy and many of the low gravity producers require all the energy which can be put into them to yield the heavy oil. Steam stimulation now appears to be the most promising and is being used by many producers in the California oil fields. Steam injection, by either of two methods, has become a complex problem. It appears that the displacement or flood technique is less troublesome once the field has been prepared for it, but the necessary flow lines and steam generating equipment makes the initial expense very high. Intermittent steam injection using the huff and puff technique may not be as costly, but it certainly has many trouble spots. It no longer appears that all that is required is a steam generator, it suitable water supply and any old well. As long as steam injection temperatures remain below 400F problems seem to be at a minimum. But as injection pressures increase with their corresponding temperature increase, unforeseen problems with the cement, cement to pipe and/or cement to formation bond and casing have arisen. This paper discusses the problems involved in obtaining a sound cementing job and suggests methods of allowing the cement to do what it is designed for.
Description and Definition of Materials Used
Much has been written on the effects of heat on cementing compositions. Laboratory investigations disclosed that above approximately 230F there was a pronounced loss of compressive strength and an increase in permeability of many compositions. Any compositions containing additives which are not chemically reactive with the cement and which cause a high water-cement ratio create poor temperature stability. Bentonite is probably the worst offender and should not be used in any composition in excess of 4 per cent by weight of the cement. We will not go into the limitations of Portland cement at elevated temperatures. It is significant, however, to stress the advantages of silica flour as a stabilizing additive at these elevated temperatures. This admixture has been evaluated in many laboratories using a wide variety of cementing compositions and found to be very beneficial. Results of the tests indicate that a minimum of 30 per cent silica flour by weight of the cement was required to obtain temperature stability with a maximum of 60 per cent by weight of cement. The more common quantity being used at the present time is 40 per cent. Table 1 presents slurry properties of compositions having application in thermal projects, while Table 2 indicates the effects of temperature upon the compressive strength.
General Properties of Materials
Cement slurries, when cured in a moist atmosphere, exhibit some slight expansion upon setting. This aids in development of bonding strength both to the pipe and to the formation.
Cementing deep, high-temperature oil wells where static temperatures range from 350 to 400F has become routine in the past decade. In the United States there were 271 wells drilled deeper than 15,000 ft during 1963. Many of these wells had static temperatures higher than 400F. Bottom-hole static temperatures near 700F are now realities in the geothermal (steam producing) wells of California's Salton Sea area. The detailed planning initiated prior to drilling the wells is discussed together with the methods, materials and equipment used in solving the cementing problems which are encountered. Data are also presented that lead to development of cementing compositions that provide adequate thickening time, do not retrogress in strength, and maintain low permeability under these extreme temperature conditions. Field data include the cementing programs used on eight relatively trouble-free geothermal steam wells in the Salton Sea area.
Not too many years ago cementing oil wells with temperatures in the range of 300F caused considerable anxiety. In some areas of the United States it is now fairly common to cement wells having bottom-hole static temperatures in excess of 400F. We are now confronted with the problem of cementing wells with temperatures ranging from 500 to 700F. Temperatures in this order of magnitude are often found in geothermal steam wells. From where does this extreme heat emanate? There are many theories as to the source of this steam flow. The most widely held views are: (1) heating of ground water fairly close to the surface by an intrusive mass of hot rock; (2) steam generation from a reservoir of metamorphic rock, normally found below 25,000 ft and not at the shallower depths of the Salton Sea reservoir; and (3) high- temperature gases (water vapor) escaping and migrating from molten or semi-molten rock (magma) at a considerable depth. Of these, No. 3 seems to be the most generally acceptable explanation. Heat from springs and fumaroles has been used for years as a means of heating and cooking; however, significant progress in harnessing the vast power of underground steam reservoirs has been relatively slow. The first large-scale attempt to use the heat generated by steam from wells was made in Italy around the beginning of the 20th century. In excess of 250,000 kw of electrical power is now being produced from holes around Larderello, Italy. Another very active drilling program was initiated in the volcanic area of New Zealand in 1949. Natural steam for power projects in the United States began in the early 1920's. An early commercial steam field is located at the Geysers, approximately 75 miles north of San Francisco, an area discovered in 1847 and used for many years as a health resort. Steam originates from 15 wells that have been drilled since 1957. The present output from this project is 25,000 kw. Success of the Geysers operation has been responsible for several companies taking a careful look at the feasibility of producing steam for power generation in the Salton Sea area of Southern California's Imperial Valley. Geothermal steam activity in this latter area began in 1961 when O'Neill, Ashmun and Hilliard completed Sportsman No. 1, at that time the hottest wellbore in the world. Since its completion seven additional wells have been successfully completed in this area.
Many problems encountered in drilling stream wells had to be oven come to make the ventures successful. Formation temperatures encountered in the Salton Sea seemed to be a straight-line function (a gradient of 13F per 100 ft of depth). This imposed severe conditions on all aspects of drilling and completion. This varied, to some extent, from gradients in the older geothermal areas. Not to be overlooked is the effect of these temperatures on casing creep or elongation by thermal expansion (Table 1), because standard API flanged wellhead equipment makes no provision for this kind of performance. Floating equipment was redesigned, and changes in types of downhole equipment were made in an effort to eliminate anticipated problems. In the later completed wells, standard oil-well cementing equipment has been used.
During the early development of geothermal steam wells there were some problems resulting from blowouts. However, these were eliminated in the deeper Salton Sea wells and no problems were encountered with the drilling mud. A sodium surfactant mud was used on the Sportsman No. 1 to drill from 2,690 to total depth. Nevertheless, it was necessary that a cooling system be added and the mud cooled before circulating it back into the well. The difficulty in evaluating the size of the steam area and its potential in terms of pounds of steam and years of productivity still bas not been resolved.
Economic complexities have also entered into the steam play in the Salton Sea. The wells at the Geysers were drilled at a cost of $15,000 to $20,000, whereas the Salton Sea wells will cost more than $150,000.
ABSTRACT Evaluation of primary cementing jobs using acoustic bond logs indicates that good cement-pipe bonding is necessary. Initial investigations proved pipe bond a function of pipe sui-face finish. Both field and laboratory data indicated an improvement in cement-pipe bond could be obtained using resin-sand coated pipe. Methods used in cement-pipe bond testing were mechanical, hydraulic, and acoustical. These bonds were determined on laboratory specimens, in experimental test wells, and actual field wells. Perforation studies were made using a resin-sand coating applied to small-diameter casing. Perforating tests were conducted on laboratory samples utilizing expendable jet charges to -evaluate the durability of resin-sand coating. INTRODUCTION Many advances have occurred since the initial use of cement in the oil-producing industry to help isolate zones and to provide protection for the casing string. Basically, these improvements can be divided into two major groups, mechanical or chemical. Mechanical improvements have been made on blending and mixing equipment, tools, casing equipment, and many other accessories. Chemical advancements include many special additives for blending with cement to control fluid loss, slurry weight, setting and thickening time, lost circulation, and other slurry properties indicated to be important for improved cementing jobs. One of the latest improvements in materials is the use of friction-reducing additives in cement. These chemicals reduce apparent slurry viscosity and allow turbulent displacement at lower pumping rates and pressures than with conventional slurries. This practice makes possible better removal of circulatable mud from the annulus during cementing to yield a more uniform sheath of cement between the casing and well bore. More recent mechanical advancements include the introduction of acoustic logging techniques for evaluation of cementing results in terms of bonding at the pipe and cement formation interfaces. Many questions have arisen concerning these logs, .since a multitude of factors influence their correct interpretations Also, considerable interest was generated in cement bonding capabilities and methods which might be applicable to improvement of this property since it affects the quality of a primary cementing job. Previous work has shown a laboratory method of determining shear, gas, and hydraulic bonds. Shear bond is the mechanical bond that supports pipe in the hole and is expressed in pounds per square inch of pipe surface contacted by cement. Gas and hydraulic bond is the resistance to gas or fluid migration a t the casing-cement interface and is expressed as the pressure, in pounds per square inch gage, necessary to initiate failure. One of the most recent methods introduced to the oil and gas industry to improve the cement-pipe bond has been the application of a resin-sand coat to the casing. This process consists of a resin film applied to the casing into which sand is then partially embedded. Resin-sand coating of casing may be classified as both a mechanical and chemical advancement. Mechanically, a resin-sand coat applied to the OD of the casing provides a larger area, as well as a rougher surface to which the cement can adhere. Chemically, the resin material must possess certain properties