Class G And H Basic Oilwell Cements

Class G and H basic oilwell cements John Bensted describes the nature, requirements and usage of the above Summary Class G and H oilwell cements are discussed in some detail. The concept of their being basic oilwell cements - in being able to be tailored to cope with a wide range of well cementing conditions, by including suitable dosages of appropriate additives to the particular cement slurries - is explained in terms of the cement quality requirements. Differences between these two oilwell cement classifications, their specifications and a description of other properties deemed desirable by the users, such as adequate slurry rheology, are outlined, so as to demonstrate the practical context in which these cements have to be utilised. Introduction Previous articles in this series have discussed the API (American Petroleum Institute) retarded oilwell cements of Classes D, E and Fl and the rapid-hardening oilwell cement of API Class C used for extending cement slurries without encountering segregation (bleeding) problem@. In the present work, the basic oilwell cements of Classes G and H are described. These latter two Classes are the most extensively employed oilwell cements around the world for the cementing of oil- and gas-wells. They are therefore the most important oilwell cements within the API classification systems. Definitions of Class G and H cements Both these Classes of oilwell cement have the same definition. They are currently defined in API Specification lOA as follows: 0 “The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulphate as an interground addition. No additions other than calcium sulphate or water, or both, shall be interground or blended with the clinker during manufacture of Class G/H well cement. This product is intended for use as a basic well cement. Available in moderate sulphate-resistant (MSR) and high sulphateresistant (HSR) Grades.” It is not defined what a basic well cement is. The previous definition4of these two classes of oilwell cements was as follows: 0 “Intended for use as a basic well cement from surface to 8000 ft (2440 m) depth as manufactured, or can be used with accelerators and retarders to cover a wide range of well depths and temperatures. No additions other than calcium sulphate or water, or both, shall be interground or blended with the clinker during manufacture of Class G/H well cement. Available in moderate and high sulphate resistant types. Cements in the Classes G and H shall be defined as the product obtained by pulverising clinker consisting essentially of hydraulic calflum silicates to which no additions other than calcium sulphate or water, or both, shall be interground or blended with clinker during manufacture”. ,Here the concept of a basic oilwell cement was inferred as one which could be used with accelerators and retarders to cover a wide range of well depths and temperatures. Individual well conditions may require the use of slurries with densities ranging from = 1.0 to ~2.4 kg/l 8-20 lb/US gal), pumping times from 2 to 6 hours, temperatures from freezing to ~200 “C (~400 OF) and 44

pressures up to 140 MPa (20 000 psi)s. The use of one cement type on the rig site is important logistically for a smooth sequence of cementing operations during well drilling. The older definition refers to Class G and H cements being suitable for use down to 8000 ft (2440 m) as manufactured, but this is not included in the new definition. The reason for this is that the depths and associated bottom hole circulating and static temperatures quoted previously in API Specification 10 were originally based upon data obtained from 71 wells in the South Western United States and Gulf of Mexico regions. In other parts of the world where drilling operations take place, different geothermal temperature gradients exist, so that the API data relating specific depths to bottom hole temperatures and pressures are not truly valid in these locations. For this reason, all references to specific well depths have been deleted in the latest specification. The chemical and physical requirements for Class G and H cements are given in Tables 1 and 2 respectively, There are no differences in chemical and physical requirements, except that for the physical and performance requirements the mix water is 44% by weight of cement for Class G and 38% for Class H. Characteristics of Class G and H cements 1. What then is the difference between Class G and Class H cement? In general Class H cements are more coarsely ground sulphate-resisting Portland cements than Class 6 cements. Surface areas of Class H cements are commonly in the range 220-300 m2/kg (with some even as low as 190 m2/kg), whilst for Class G cements the surface area range is usually 270-350 m2/kg (with some as highas 380 m2/kg). Surface areas of Class G cements from the same manufacturing source as Class H cements are indeed more finely ground. However with cements from different sources, where clinker phases (through the use of different raw materials, fuels and processing) may have different reactivities, a particular Class G cement may indeed be coarser than a particular Class H cement. The key factors in determining which class a basic oilwell cement belongs to are the performance tests, conducted at 44% water for Class G and 38% water for Class H cements. 2. Are HSR Class G/H cements better than their MSR counterparts? The problem of whether HSR Class G or H cements are intrinsically better than their MSR counterparts again cannot be generalised. Sometimes HSR Class G or H cements are better in terms of their rheological properties than the corresponding MSR Class G or H cements from the same plant. This can arise in respect of the C,A (aluminate phase) content of the cement. In HSR cements the C3A content is limited to 3%, whilst in MSR cements the C,A limit is 8%. In MSR cements if the Cd content is high (= 6.5% or more) then cement slurries can become more thixotropic than is desirable, even if the cement is still within specification. This problem can often be overcome, or at least minimised, by keeping the CBA content as low as possible. Other factors like C$ reactivity, free lime, free magnesia etc. also affecl rheological behaviour, so the level of C3A cannot be considered in isolation. WORLD CEMENT APRIL 1992

In the exacting well cementing environment of the North Sea, only HSR basic cements have been used, until recently Class G but now sometimes Class H in addition. This does not mean that MSR cements would not work satisfactorily. It means that because &A content is limited to 3% or below, one of the potential causes of high thixotropy in cement slurries has been controlled. However, even when &A level is kept low a Class G or H cement slurry can still be thixotropic if other factors are not suitably controlled5s6. Generalisations cannot be made across the board, because there are numerous instances of some MSR Class H cement having better rheological properties than other HSR Class H cements. Similar comments apply to comparisons of MSR and HSR Class G cements too. In the United States, MSR cements of Class H and Class G have traditionally been preferred, but now increasingly HSR cements of both Class H and G are being produced and used in well cementing. This has arisen because rheological parameters have sometimes been easier to control in the HSR cements because of the inherently lower C,A content. Sometimes MSR cements are more convenient to manufacture as a particular works’ raw materials may not need iron oxide additions to produce them, whereas for the HSR cements such additions and maybe those of some silica sand as well as usually necessary to produce the required CBA content. 3. Why are there two basic oilwell cement types - Class G and Class H? The reasons for this are historical and began within the United States. The original concept of the basic oilwell cement was developed in California, where a standard water requirement of 44% by weight of cement was set, and this was called Class G. However, in the more traditional oil areas of Texas, Oklahoma and Louisiana there was concern about this, since they liked the 38% water requirement of the medium and deep oilwell cements of Classes D, E and F which was well understood. Accordingly there was an insistence upon having a water requirement of 38% for a basic cement. Certainly in areas like South Louisiana they wanted a basic oilwell cement like the Class D, E and F cements, but without added retarders. The API then agreed to have a second basic oil well cement with a fixed water requirement of 38% for standard testing, which was designated Class H. Originally only the MSR Class H cement was fully sanctioned, the HSR designation being tentative for some time before being fully accepted. An interesting point is that in practice in cementing formulations, Class H cement is often utilised at higher water levels than 38% by weight of cement - sometimes as high as 46% or even more. Also, Class G cement is commonly used at water levels other than 44% by weight of cement. Traditionally Class H cement has been employed for well cementing in most of the United States, with Class G cement being used in California, the Rocky Mountain region and Alaska. Elsewhere in the world Class G cement has generally been preferred as the basic oilwell cement. In the North Sea, HSR Class G cement was the only basic oilwell cement type utilised until recently, when HSR Class H cement also began to appear on the scene. In the United States MSR cements of Class G and H have been used, as mentioned above, but now HSR Class G and H too cements are increasingly making their appearance. MSR Class H cement is also produced in Venezuela6, where it is extensively employed. Some years ago the API proposed to rationalise the two basic oilwell cements of Class G and Class H into one. It was suggested that there should be just one basic oilwell cement, to be called Class L, which would be tested for physical (cementing) requirements at a water level of 42% by weight of cement, in between that already pertaining to Class G and H cements, and thus be able to supersede these two established basic 46

Classes. The chemical analysis and physical tests would have been the same as those for Class G and H cements. The proposal was not accepted, because in the different operational areas of the world, most users were satisfied with the existing basic cements of Class G and Class H and had extensive data bases of cement slurry formulations, which would have been less useful for comparisons with a Class L cement based upon a different water water requirement. 4. Does oilwell cement quality depend upon the type of manufacturing process, viz. wet, semiwet, semidry or dry? Again, one cannot generalise with clear-cut answers. At one time in older plants it was probably easier to control the manufacturing process when it was wet rather than dry. However, with modern and updated plants involving computerised process technology, the type of manufacturing process should not matter from the oilwell cement quality angle. Each particular cement plant can be adapted to produce good quality oilwell cement with the right process technology and staff skills, so the actual type of process per se should not present any inherent disadvantages. Points arising from these questions

Clearly one cannot depend upon generalisations of basic cement Class, level of sulphate resistance or the kind of manufacturing process to determine which oilwell cements give the best downhole cementing performance. Suitably simulated performance tests are the only true guide for assessment of which particular, individual Class G/H cements are acceptable at a given time for a given situation. Manufacture Oilwell cements are manufactured using the normal raw materials and processes employed as for ordinary, moderate or high sulphate resistant Portland cement. The compound composition obtained will, of course, vary within the set limits of the appropriate specification, depending upon the targets set by the manufacturer. This takes into consideration the materials and plant avail. able, as well as the route which gives the best quality control. Figure 1 shows an aerial view of a cement plant where HSR Class G cement is produced. The manufacture of oilwell cement is summarised by reference to the basic cement Class G. Certain modifications are necessary in comparison with the production of sulphate-resisting Portland cement for the construction industry. Construction cements need to be more reactive so that satisfactory compressive strength development can be achieved at early stages, whilst for oilwell cementing the cements need to be less reactive to give an adequate placement time that can allow for stoppages, and also to prevent excessive quantities of additives like retarders and dispersants being necessary to control the rate and manner of thickening of the cement slurry. For consistency of response to the effect of additives, during oilwell cement manufacture, variations in materials, proportioning and processing must be minimised at all stages during the process. The onus is on the manufacturer to consistently maintain a ‘good housekeeping’ policy at the plant. Class G cement is made from a raw meal containing a calcareous component (such as chalk or limestone), an argillaceous component (clay or shale), a source or iron oxide (such as haematite or pyrites residues) and, if necessary, a small addition of quartz sand to allow sufficient silica to be present in toto in the raw meal. The composition of the raw meal is designed to produce a clinker of suitable reactivity for oiiwell cement usage. For HSR as opposed to MSR Class G cement, relatively more iron oxide needs to be incorporated in the raw feed to produce more ferrite phase at the expense of tricalcium WORLD CEMENT APRIL

1992

ire 1. Aerial view of a cement factory where HSR Class G oilwell cement is manufactured.

aluminate. These components are ground together to achieve a fine homogeneous mix either with water in a slurry (wet process) or in a grinding mill in the dry state Mry process). From the slurry tanks or grinding mills the raw meal is fed to a rotary kiln, where it is burnt to the point of incipient fusion (ca. 1400-1450 “C). Combination is completed and a clinker is produced, which is cooled on leaving the kiln. The free lime content of the clinker should not exceed ca. 1% for low MgO cements or ca. 0.5% for high MgO cements, otherwise the cement is likely to have poor retardation, rheology and fluid loss properties. Worldwide there are some individual exceptions to this, but in general this is a useful ‘rule-ofthumb’ guide. Oil and gas are commonly used kiln fuels, although coal or lignite of low ash content and some petroleum coke may be used if reducing conditions within the kiln can be avoided. Reduction causes some change of iron (ill) to iron (II), as a result of which less ferrite phase is formed and more tricalcium aluminate is produced than would normally be expected. The iron (II) substitutes for calcium in the clinker phases being formed, which creates more difficult combinability and necessitates ?arder burning. Overburning should in any event be avoided, because it produces a clinker insufficiently qactive from the oilwell cementing viewpoint. In addition. reduction in the kiln assists dissociation of alkali sulphates present in small quantities, which causes the released alkali metal ions to become incorporated in solid solution in the main clinker phases. Such incorporation in the tricalcium aluminate phase alters its chemical reactivity and causes potential deliquescence in the clinker produced. Sulphur dioxide woduced by the effects of the volatilisation may assist in producing undesirable kiln build-ups and possible blockages. The overall effects of reduction on the cement are to give rise to poor rheological properties, poor ___._. - -. KIRLD CEMENT APRIL 1992

development of compressive strength, poor handling problems, normally faster thickening, and a greater susceptibility to aeration. Slowly cooled clinker also gives rise to a faster setting (thickening) cement. After cooling, the clinker is ground with ca. 24% gypsum in a grinding mill to produce a Class G cement with a surface area in the range ~270350 mYkg. The grinding temperature should be kept as low as possible to minimise dehydration of gypsum to hemihydrate or soluble anhydrite. Excessive gypsum dehydration can cause two problems: (i) false set or early stiffening, which can give rise to rheological problems during pumping and/or placing: (ii) extra sulphate ions in solution in the slurry which can accelerate alite (tricalcium silicate) hydration and thus cause the cement to be unacceptably reactive. Gypsum addition is normally kept low, giving a total cement SO3 content within the range 1.7-2.3% (again to minimise the acceleration of the hydration reaction of alite with sulphate). Higher SO3 levels may be tolerated if the total alkali content is low. Class H cement is produced by a similar process, except that the clinker and gypsum are ground relatively coarser than for a Class G cement at the same plant, to give a cement with a surface area generally in the range 220300 mYkg. Experience involved in the production of MSR Class H oilwell cement has been described6. Quality control Generally speaking, for oilwell cement usage, higher levels of product quality and of quality control at the plant are required than for the different types of Portland cements made for the construction industry. This is necessary because of their being subjected to more exacting conditions of reaction-thickening and hardening - under different conditions of temperature and pressure downhole. The API have introduced a specification for quality 47

programmes, API Specification Q17. However, this is not fully compatible with the IS0 9000 series. Under the APIIS0 liaison, this matter is being looked into with a view to API Specification Ql and IS0 9001 being made fully compatible. It needs to be emphasised that the basic oilwell cements of Class G and Class H are expected to perform satisfactorily over a wide range of well conditions5. In usage, they are commonly mixed with different types of additives for producing satisfactory slurry performances in given wells. Details of such additives have been described5. Consequently such cements need to give consistent batch-to-batch performance wherever possible, in order to optimise well cementing operations. Chemical requirements (Table 1) These are the same for both Class G and Class H cements, differences lying in the MSR and HSR requirements for both classes of oilwell cement. C$.S is limited to 4858% for MSR cements and 4865% for HSR cements to assist with obtaining cements of reasonable batch-to-batch consistency. Total alkali content is limited to 0.75% Na,O equivalent and SO3 to 3.0% for guarding against over-reactive cements. MgO is limited to 6.0% as a precaution against unsoundness. C,A is limited to 8% for MSR cements and 3% for HSR cements. Maximum requirements for loss-on-ignition (3.0%) and insoluble residue (0.75%) are taken from ASTM construction cement requirements and are indirectly useful parameters for maintaining product quality. No free lime limits are specified, although it is well known that high free lime can create difficulties with cement slurry rheology and retarder response. As a general ‘rule-of-thumb’, free lime should normally be below 0.5%, although up to 1.0% may be satisfactory if the total MgO content of the cement lies below 1.5%. A free lime limit of 2.0% is actually specified in the Brazilian standard for Class G oilwell cement*. Although this limit may appear to be on the high side, it reflects the national Class G cements where free lime can lie well above 1.0% and the cement can still be satisfactory in use, due to the specific conditions pertaining to the cements concerned. Table 1. API Specification IOA: Chemical requirements for Class G and Class H cements Cement type: MN so3 Loss on ignition Insoluble residue

MSR

HSR

itif

6.0 3.0

48-68 8

48-65 3

3:o 0.75

E5

2: C4AF +!2 x &A Na,O Equivalent 0?5 0.75 rll figures are % maximum, except for C,S where the permiti ange is given. Physical and performance requirements (Table 2) The physical and performance requirements of Class G and Class H cement are the same, the only difference being that Class G cements are tested at 44% water whilst Class H cements are examined at 38% water. In the latest specification3, the previous requirement of an autoclave expansion test limit of 0.8% for unsoundness4 has been deleted. Since most Class G and H cements give autoclave expansions of 0.05% or less (over an order of magnitude lower than the former test limit), this test had for some time been widely regarded as being superfluous for these two types. The requirement for Schedule 5 thickening time (to 52 “C) of 90-120 minutes, which only offers a leeway of 30 minutes in thickening time, is a useful test for seeking to promote batch-to-batch consistency. Thickening time is 48

merely a setting time under controlled pressure and temperature conditions, designed to simulate the conditions under which given cement slurries are pumped into position downhole. The need for a maximum consistency of 30 Bc during the first 15.30 minutes of this test is an indicator that Class G and H cement slurries should be sufficiently fluid to enable pumping downhole into position in the annulus to be as trouble-free as possible. An example of a Schedule 5 thickening time curve for an MSR Class H cement is shown in Figure 2. The compressive strength minimum requirements for8 hours at atmospheric pressure at 100 “F (38 “C) and 140 OF (60 “C) of 300 psi (2.1 MPa) and 1500 psi (10.3 MPa) respectively are well above the minimum values required to support a metal casing in the well (generally = 150 psi) and thus represent a valuable inbuilt safety margin. The free water test has now been renamed the free fluid test and is a measure of the amount of bleedina that takes place under the test conditions. Table 2. API Specification 10A: Physical and performance requirements for Class G and Class H cements Mix water (% by weight of cement) - Class G - Class H Schedule 5 Thickening Time (minutes) Maximum consistency during first 15-30 minutes of Schedule 5 test (Bc) Compressive strength L psi (MPa) - 8 hours, atmospheric pressure, 100 OF (38 “C) - 8 hours, atmospheric pressure, 140 OF (62 “C) Free fluid (ml)

44 38 90-120 3Omax 300 (2.1) min 1500 (10.3) m 3.5 max

Other performance tests Operators and cementing service companres normally want Class G and H cements to perform well beyond these specification limits. As a result, many cement manufacturers often undertake additional retardation tests using appropriate API Scedules4 and typical retarders as a rough check on likely downhole perform ante. Some also undertake rheological tests using a rotational (Fann-type) viscometer for checks on the rheological properties of the cement slurries. Cement rheology is an extremely complex subject. Cement slurries are non-Newtonian fluids that are chemically reacting all the time they are being mixed and p u m p e d i n t o p o s i t i o n i n t h e annulus. The exact rehological behaviour is dependent upon the precise conditions to which the cement slurry is subjected. Laboratory simulations of cement rheology provide a rough guide to likely downhole performance. Rotational viscometers like the Fann have been used extensively in laboratories for obtaining data using the procedure described in Appendix H of API Specification 104. The Brazilian standard for Class G oilwell cement has defined limits for rheological parameters using rotational viscometers (see Table 3) which are satisfied by the ,Brazilian Class G cements. In practice elsewhere, some Class G and H cement slurries have yield points in these standard rotational viscometer tests above 100 lb/l00 ftr and are still readily pumpable. It is often difficult with cement slurry rheology to differentiate between what is desirable and what is essential in terms of rheological characteristics obtained by rotational viscometers in the laboratory, since the labortory conditions do not reliably simulate those in the field. Consquently it is much more difficult on a worldwide basis to have strict pass/fail rheological requirements for standard slurries of the whole range of Class G and H cements. A more explicit description of the procedure for Farm.’

Thickening time - 103 minutes Maximum consistence during first15-30 minutes of the Schedule 5 examination - 15 Bc (Water: Cement ratio 0.38)

8 0 I-

60

I I I I I I I

I

0 0

I

I

I

I

20

40

60

80

Thickening time 1

100

120

Time (minutes) --) $ure 2. API Schedule 5 thickening time curve of an MSR Class H cement.

:ype rotational viscometers in terms of standard speeds of the 600 and 300 rpm readings (designated here rrxn or radians/second) was contained in a previous respectively as A and B) to calculate: edition of API Specification log. EarlierlO, a 800 rpm (10.0 radians/second) speed was also recommended in API apparent viscosity $ (cP) Specification 10. This was subsequently deleted from the loecification. because it was felt that the shear rate plastic viscosity A-B(cP), and I=1000 set-l) was far greater than that likely to be yield point 2B-A (lb f/l00 ft2), encounteredby a cement slurry being mixed and pumped the field. However, when dial reading (corrected for Q which are based upon 1 CP g 0.002089 lb f sec/lOO ft2. range factor as appropriate) is plotted against speed, the Whilst this ‘rule of~thumb’ might disturb the rheological 800. 300, 200 and 100 rpm-based results commonly purist, in most instances the results for plastic viscosity @proximate to a straight line. In consquence many users and yield point are of the same order of magnitude as #ill make use of the 600 rpm reading. Normally when the those plotted out by ‘computer best-fit’ or manual slurries are not too thick, this does not significantly procedures from the full range of rotational viscometer readings. This ‘rule of thumb’ 600 or 300 rpm reading change the results, even though strictly speaking the non-mandatory API practice now is to recommend the usage is probably most appropriate for cement @e of a rotational viscometer capable of measuring manufacturers quickly checking out rheological properties of production batches, to see if there are any shear stress at shear rates in the rate from near zero very significant differences in rheological behaviour -‘) to as high as 511 (set-l) which corresponds to the rpm reading. between one cement batch and another under the For convenience, various laboratories make use solely standard slurry conditions employed. Cementing services companies and operators generally need to fabls 3. Rheologlcal propsrtla~s of Class G cement slurries as in make use of the full range of readings. kc Brazflian standard An example of a ‘computer best fit’ curve for shear - ___ __ stress plotted against shear rate for an HSR Class G 27 OC (BB OF) 52 Yi (125 =‘F) cement (making use of the 800, 300, 200 and 100 rpm 8 seconds gel strength at readings) is illustrated in Figure 3. kpm -Pa (lb/100 ft2) 12 (25) max 12 (25) max W minutes gel strength at 3rpm -Pa (lb1100 ftg2, 16.8 (35) max 16.8 (35) max “Zrnsistency after 1 minute at 3rpm -Pa (lb/lOCl ft2) 9.6 (20) max 9.6 (20) max . “msistency after 5 minutes at drpm -Pa (lb/lOfJ ft2) 9.6 (20) max 9.6 (20) max ‘hstic viscosity -Pa.s (cp) 0.055 (55) max 0.055 (55) max %ld point -Pa (lb1100 ft2) 14.4-33.5 (30-70) 14.438 (3080) Cimum increment of 10 minute pl strength with temperature rise klm27~C(85V=)to52°C(125~F) 4.6 (10) max hNJ/1Orl ft2)

Conclusion Class G and H basic oilwell cements have been considered from both the producer and user aspects. Differences between these two classes have been outlined from the viewpoint of specification and other properties favoured by the users. The importance of having a Class G or H cement slurry with good batch-tobatch consistency, which can be tailored with different types of additives to achieve a satisfactory bond in the annulus between the metal casino and the borehole, is 49

I 200

1 400

I 600

I 800

I 1000

Shear rate ‘/s Figure 3. Shear stress versus shear rate for an HSH Class ci cement. emphasised in terms of the greater quality control required during manufacturing and for performance testing compared with most construction cements. Acknowledgements The author wishes to thank the following: Regis Nivesse and the directors of Cedest SA for permission to use the photograph of their cement works at Dannes, France. Fernando J Parente Neiva Santos and Maria das Gracas Pena Silva of Petrobras - CENPES, llha do Fundao, Rio de Janeiro, Brazil, and Cesar Arbelaez of CA. Venezolana de Cementos (Vencemos), Barquisimeto, Venezuela, for helpful discussion. BP international Ltd. for permission to publish this work. References 1. BENSTED J.; Retarded oilwell cements of API Classes D, E and F. World Cement, January 1991, pp 31-35. 2. BENSTED J.; API Class C rapid-hardening oilwell cement. World Cement, May 1991, pp 38-41. 3. AMERICAN PETROLEUM INSTITUTE. Specification for Well Cements, API Specification IOA, Twenty First Edition. American Petroleum Institute, Washington DC, September, 1991. 4. AMERICAN PETROLEUM INSTITUTE. Specification for Materials and Testing for Well Cements. API Specification 70, Fifth Edition. American Petroleum Institute, Washington DC, July 1990. 5. BENSTED J.; Oilwell cements. World Cement, October 1989, pp 346357. 6. ARBELAEZ, C. Experience at CA Venezolana de Cementos in the Production of API Class H Oilwell Cement. Proceedings of the Twelfth International Conference on Cement Microscopy, 2nd.6th April 1990, Vancouver, Canada. pp 264-279. International Cement Microscopy Association, Duncanville, Texas (1990). 7. AMERICAN PETROLEUM INSTITUTE. Specification for Quality Programs. API Specification Q7, Third Edition. American Petroleum Insti&te, Washington DC, June 1990. 8. ASSOCIACAO BRASILEIRA DE NORMAS TECNICAS. NBR 9831 - Cimento Portland Destinado a Cimentaczo de Pocos Petroliferos. (NBR 9831 - Portland cement for use in the cementation of oilwells). ABNT, Rio de Janeiro (1987). 9. AMERICAN PETROLEUM INSTITUTE. Specification for Materials and Testing for Well Cements. Third Edition. American Petroleum Institute, Washington DC, July 1986. 10. AMERICAN PETROLEUM INSTITUTE. ibid., 1st Edition, June 1982. Enquiry no.12 50

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