a geopolymer cementing system for oil wells subject to
TRANSCRIPT
Accepted Manuscript
A geopolymer cementing system for oil wells subject to steam injection
Maria D.M. Paiva, Emílio C.C.M. Silva, Dulce M.A. Melo, Antônio E. Martinelli, José F.Schneider
PII: S0920-4105(18)30510-2
DOI: 10.1016/j.petrol.2018.06.022
Reference: PETROL 5029
To appear in: Journal of Petroleum Science and Engineering
Received Date: 17 January 2018
Revised Date: 3 June 2018
Accepted Date: 7 June 2018
Please cite this article as: Paiva, M.D.M., Silva, Emí.C.C.M., Melo, D.M.A., Martinelli, Antô.E.,Schneider, José.F., A geopolymer cementing system for oil wells subject to steam injection, Journal ofPetroleum Science and Engineering (2018), doi: 10.1016/j.petrol.2018.06.022.
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A GEOPOLYMER CEMENTING SYSTEM FOR OIL WELLS SUBJECT TO STEAM 1
INJECTION 2
Maria D.M. Paiva1, a, Emílio C.C.M. Silvab, Dulce M.A. Meloc, Antônio E. Martinellid and José F 3
Schneidere 4
Corresponding author 5 1 UFRJ, POLI/COPPE, NUMATS 6 Av. Athos da Silveira Ramos, 149 (Bloco I-110) 7 Cidade Universitária 8 Rio de Janeiro, RJ - 21941-972 - Brazil 9 [email protected] 10 11 a Universidade Federal do Rio Grande do Norte (UFRN), Programa de Pós-Graduação em Ciência e 12
Engenharia de Materiais. 13 Av Salgado Filho 3000 14 Lagoa Nova 15 Natal, RN - Brazil 59072970 16 17 b Petróleo Brasileiro S.A, CENPES 18
Av. Horácio Macedo, 950, Escritório 8, CENPES/Ampliação 19 Cidade Universitária 20 Rio de Janeiro, RJ - 21941915 – Brazil 21 [email protected] 22
23 c UFRN, Centro de Ciências Exatas, Instituto de Química. 24
Av Salgado Filho 3000 25 Lagoa Nova 26 Natal, RN - 59072970 – Brazil 27 [email protected] 28 29 d UFRN, Centro de Tecnologia, Departamento de Engenharia de Materiais. 30
Av Salgado Filho 3000 31 Lagoa Nova 32 Natal, RN - 59072970 - Brazil 33 [email protected] 34 35 e USP, Instituto de Física de São Carlos, Departamento de Física e Ciência Interdisciplinar. 36
Av.Trabalhador São-carlense, 400 37 Centro 38 Caixa-postal: 369, São Carlos, SP - 13560-970 - Brazil 39 [email protected] 40 41
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42
ABSTRACT 43
Oil wells subjected to cyclic steam injection often present cement sheath failures due to thermal 44
loads. Currently, different Portland based systems are employed to mitigate this risk. We developed 45
and tested geopolymer systems that meet oil well cementing requirements and achieve high 46
mechanical performance. A metakaolin-potassium-based formulation, containing microsilica, 47
mineral fiber and retarder, was adjusted to the desired rheology and thickening time. Triaxial 48
compression and indirect tensile tests were performed and the properties were used in finite element 49
simulations of the life of a model onshore well. Compared to the Portland based system currently in 50
use, the geopolymer has superior uniaxial compressive strength and lower stiffness. Tensile strength 51
increased significantly with the addition of mineral fibers and became higher than that of the 52
Portland system. Numerical simulations show that the geopolymer can withstand steam injection 53
temperatures comparable to a conventional system, remaining in the elastic region. These results 54
show that geopolymers are a viable alternative well cementing system for this application, with 55
significant improvement in mechanical performance. 56
Keywords: geopolymer; alkali-activated binder; well cementing integrity; mechanical properties; 57
triaxial testing; computer simulation. 58
1 INTRODUCTION 59
The cement sheath in an oil well must provide structural support to the casing and surface 60
equipment, compose the well barrier against fluid migration, protect the casing from corrosion and 61
isolate production zones (Nelson, 1990). Cement is placed in the annulus between the casing and 62
the borehole wall by pumping slurry through the casing and displacing the previous fluid in the 63
annulus. After setting, the cement will bond to the external wall of the casing and to the borehole 64
wall, which may be a previous casing string. 65
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There are two sets of requirements for a cementing system. In the fluid state, the density and 66
rheology of the slurry must be adjusted to keep downhole pressures, due to hydrostatics and to 67
friction losses, within an operational window. Rheological properties must be maintained for the 68
duration of the cementing operation, but setting and strength evolution must be as fast as possible 69
after placement. In the solid state, the requirements include mechanical strength, low permeability 70
and resistance to chemical degradation (Nelson, 1990). 71
Onshore oil fields in northeastern Brazil contain shallow sandstone formations bearing heavy oil, 72
intercalated with potable water aquifers, both of which are very important to the local economy. 73
Current exploration techniques, described by Rosa et al. (2006), employ continuous and huff-and-74
puff steam injection to improve productivity and recovery factors of these heavy oil formations. 75
These techniques expose the cement sheath to large temperature variations during its operating life, 76
which expose the cement to extreme stress states (Bour, 2005; Dean and Torres, 2002). 77
The main mechanism is the thermal expansion of the casing, compressing the cement sheath against 78
the formation. Possible failure modes include radial cracking due to tangential stresses, compressive 79
failure and debonding at the interfaces between the cement sheath and casing and/or rock. 80
Dean and Torres (2002) reported that cement sheath failures in Brazilian onshore fields are mainly 81
due to radial cracking. In some cases, there is an increase in water fraction due to loss of zonal 82
isolation and steam may be observed at the surface. Beside the high costs of remedial jobs, there is a 83
risk of contaminating aquifers used by the local population. Bour (2005) analyzed numerically a 84
model well in Central California in a very compliant formation. Tensile failure was the primary 85
failure mechanism for all well geometries, since the formation did not confine the cement. 86
Bour (2005), as well as Goodwin and Crook (1992) detail requirements for the design of cement 87
slurries for steam injection wells, recommending that slurries must be compliant, resilient, ductile 88
and strong in tension. Finite element analyses demonstrate that conventional Portland-based slurries 89
with silica addition are not suitable for these conditions, having high compressive strength but low 90
tensile strength and significant brittleness. 91
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Alternative ordinary Portland cement (OPC)-based slurry formulations proposed in the literature 92
and sold commercially usually include additions such as mineral fibers and/or elastomers. In 93
northeastern Brazil, latex-based slurries are routinely used to improve the mechanical properties, 94
with mixed results (Dean and Torres, 2002). 95
Geopolymers (Davidovits, 1991, 1994a) or alkali-activated binders (Pacheco-Torgal et al., 2008) 96
are inorganic polymers composed of silicate and aluminate tetrahedra linked by shared oxygen 97
atoms and stabilized by cations such as Na+ or K+. The structure is analogous to zeolites; however, 98
their structure is amorphous or semicrystalline. Geopolymers are formed by activating source 99
materials with an alkaline solution, usually a combination of hydroxides and silicates. Fly ash and 100
metakaolin (calcinated kaolin) are common sources of silica and alumina, but several other 101
materials can be used (Olawale, 2013). 102
Compared to Portland-based formulations, the use of geopolymers (Davidovits, 1991) for well 103
cementing is still in early stages. Based on work by Marinho (2004), Nóbrega (2006) and Pinto 104
(2007), Paiva (2008) developed formulations that are equivalent to cement slurries when tested with 105
API RP 10B-2 (2013) methods. However, effective retarders of the geopolymerization reaction 106
were necessary to achieve the thickening time required in cementing operations. Cementing service 107
company Schlumberger published two patents (Barlet-Gouedart et al., 2010a, 2010b) on the use of 108
geopolymers in oil well cementing, followed by Halliburton (Chatterji, 2016), which proposed 109
alternative slag- and pumice-based compositions. These and more recent patents, such as (Porcherie 110
et al., 2016), focus on effective retarders to enable application in diverse well environments. In one 111
of the first field applications, cementing service company Sanjel employed hybrid slurries with up 112
to 60% geopolymer in more than thirty wells in Alberta, Canada, with cost savings and good 113
mechanical properties (Mahmoudkhani et al., 2008). 114
Khalifeh et al. (2014) evaluated fly ash based geopolymers for plug and abandonment using API RP 115
10-B (2013) tests, finding that the materials are suitable for use, while pointing that gelation and 116
rapid setting are major concerns. Salehi et al. (2016) performed a sensitivity analysis, observing that 117
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optimization of the mix design is critical for well cementing geopolymers. Salehi et al. (2017, 2018) 118
expanded this work with a comprehensive set of API tests, obtaining a geopolymer mixture with 119
potential to replace OPC well cementing systems. The authors tried different classes of retarders 120
and plasticizers, reporting difficulties in obtaining reliable behavior, as well as shortcomings of the 121
API thickening time procedure when applied to geopolymers. 122
Two major challenges for ordinary Portland cement in current well applications are salt and CO2-123
rich environments, such as the Brazilian pre-salt (Alves et al., 2009). Nasvi et al. (2012a, 2012b, 124
2014c) evaluated pure geopolymers in salt solutions and their applicability as CO2 sequestration 125
well cements. Besides economic and environmental advantages, geopolymers exhibit higher 126
durability (Nasvi et al., 2014b), resistance to acids and chemical attacks (Nasvi et al. 2014a), as well 127
as the higher strength compared to OPC pastes (Nasvi et al., 2014c), better bond to casing (Salehi, 128
2017), less shrinkage (Salehi, 2018), no carbonation and no alkali-aggregate reaction. Nasvi et al. 129
(2012a) studied the mechanical behavior at downhole conditions, identifying changes in 130
deformation capacity and failure mode with temperature. Brine reduces the strength of geopolymers, 131
but this reduction is less pronounced than the analogous effect on OPC-based pastes (Nasvi et al., 132
2012b; Giasuddin et al., 2013). Combined with a very low permeability at downhole conditions 133
(Nasvi at al., 2014b), compared to API requirements and OPC pastes, these properties make 134
geopolymers an advantageous alternative for zonal isolation in aggressive well environments. 135
An undesired property of geopolymers is their brittleness and low tensile strength, requiring 136
reinforcement (Silva, 2000; Thaumaturgo and Silva, 1999). A comprehensive review by Sá Ribeiro 137
et al. (2017) discusses how additions, such as particles and fibers, can enhance compressive, tensile 138
and flexural strength, increase fracture toughness and ductility of geopolymer composites. 139
Challenging applications, such as cementing oil wells subject to steam injection, explore the limits 140
of what is economically feasible to obtain with Portland-based cementing systems. Alternative 141
cementing systems may outperform ordinary materials and simultaneously reduce costs and the 142
carbon footprint of well construction. Application of these systems require demonstration that all 143
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operational requirements are satisfied and that mechanical and zonal isolation objectives will be 144
achieved. The new system developed in this work was subject to a full set of industry-specific tests 145
and was proven to maintain its characteristics over the life of the well, by numerical simulation. 146
2 EXPERIMENTAL 147
2.1 Materials and mix design 148
A Portland-based formulation (P2) used in the field was prepared using a local cement provided by 149
CIMESA, similar to API Class G. This formulation is a 1790 kg/m3 [15.0 ppg] slurry with w/c ratio 150
0.63, 40% microsilica by weight of cement (bwoc), supplied by Elkem and 50 mL per kg of cement 151
[0.6 gps] latex. All additives (latex, latex stabilizer, defoamer, dispersant and fluid loss control) 152
were supplied by Halliburton Brazil. Styrene-butadiene latex is supplied as a water-internal, oil-153
external emulsion of latex polymer, which is stabilized by a separate emulsifying additive 154
(ethoxylated nonylphenol). The defoamer is based on polypropylene glycol. The combined 155
dispersant and fluid loss control additive is a sulfonated organic salt condensate. The second fluid-156
loss additive is a copolymer of 2-acrylamido-2-methylpropane sulfonic acid (AMPS) and N,N-157
dimethylacrylamide (NNDMA). 158
Geopolymer formulations P3, P4 and P5 are based on metakaolin from Metacaulim do Brasil, using 159
potassium hydroxide p.a. from Vetec and potassium silicate solution from Diatom do Brasil as 160
alkaline activators. Two batches of metakaolin were used, labeled “Metakaolin RN” and 161
“Metakaolin RJ”, found to be very similar in terms of physical and chemical characterization. Most 162
of the work was done with the first batch, except for formulations P3.B, P4.B and P5.B, described 163
below, which used the second batch. A polypropylene glycol-based defoamer provided by 164
Halliburton Brazil was used in all cases. P5 uses a copolymer of AMPS and acrylic acid as a 165
retarder additive, supplied by Halliburton Brazil. 166
To the base geopolymer formulation P3, P4 adds 10.6% microsilica (by weight of metakaolin, 167
b.w.o.m.) and 43 mL per kg of metakaolin [0.5 gps] of AMPS-based retarder. P5 is also based on 168
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P3, adding 5.3% b.w.o.m. microsilica and 2.1 vol. % natural wollastonite, provided by Energiac. 169
Molar ratios were kept fixed at SiO2/Al2O3 = 3.8, K2O/Al2O3 = 1.0 and H2O/K2O = 12. Resulting 170
densities varied between 1690 kg/m3 [14.1 ppg] and 1730 kg/m3 [14.4 ppg]. The design parameters 171
of the geopolymer formulations are listed in Table 1 below. 172
Starting with a fixed weight of pure metakaolin, microsilica (if applicable) is added as a weight 173
fraction of the metakaolin. Next, the amount of potassium silicate solution is calculated to obtain 174
the desired SiO2/Al 2O3 ratio. The K2O/Al2O ratio is reached by adding potassium hydroxide. 175
Finally, water is added until the H2O/K2O ratio is obtained. To this base geopolymer, the retarder 176
and defoamer are added as fixed volumes per unit mass of metakaolin. Finally, the wollastonite 177
mass is calculated to obtain the desired volume fraction of fiber addition. 178
Table 1 – Mix design parameters, additions and additives. 179
Parameter Units P3 P4 P5 Control material*
Microsilica % b.w.o.m. 0 10.6 5.3
SiO2/Al 2O3 - 3.8 3.8 3.8 K2SiO3(aq) K2O/Al2O3 - 1.28 1.0 1.0 KOH(s)
H2O/K2O - 12 12 12 Water
Retarder mL/kg [gps] 0 43 [0.5] 43 [0.5]
Defoamer mL/kg [gps] 1.7 [0.02] 1.7 [0.02] 1.7 [0.02]
Wollastonite vol. % 0 0 2.1
* Material used to obtain the given molar ratio.
The target molar ratios of P3 were based on studies performed by Marinho (2004), Nóbrega (2006) 180
and Pinto (2007). The SiO2/Al2O3 ratio was chosen to maximize the compressive strength (Duxson 181
et al., 2005; Steveson and Sagoe-Crentsil, 2005). The target K2O/Al2O3 ratio was 1.0 to prevent 182
incomplete polymerization of the geopolymer network (Davidovits, 1991). P3 required a higher 183
value (1.28) to keep the target H2O/K2O with the available materials. The H2O/K2O controls 184
directly the alkalinity of the activator and the workability of the slurry. We fixed this parameter at 185
12, which to obtain workable slurries for oil well applications. Decreasing this parameter leads to 186
very short setting times (Paiva, 2008) due to the increase in alkalinity. 187
Microsilica was introduced as an alternative source of silica, to reduce the potassium silicate 188
requirement, therefore decreasing the cost and improving the handling in the field. Fixing the 189
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microsilica/metakaolin weight ratio, we kept constant the total amount of solids, since Paiva (2008) 190
determined that more than 38 vol. % of solids resulted in viscosities above the target of 0.150 Pa.s 191
[150 cP]. The volume fraction of mineral fiber was fixed to obtain a constant reinforcement effect. 192
Due to its effect on viscosity, we reduced the amount of microsilica when adding wollastonite. 193
Additives were specified in amounts compatible to those used in OPC-based slurries, using field 194
units (1 gps is 1 gallon [3.7854 L] per 94 lbs [42.64] sack of cement) and replacing metakaolin for 195
cement. 196
Two different curing regimes were employed for geopolymer formulations P3, P4 and P5. 197
Geopolymer samples cured with pressure are labeled with the suffix B (P3.B, P4.B and P5.B) to 198
distinguish them from those cured at atmospheric pressure (P3, P4 and P5). Those pressure-cured 199
samples were prepared using the “Metakaolin RJ” batch, using the design method above to 200
reproduce the same molar ratios and obtain the same geopolymer matrices. 201
2.2 Characterization 202
Physical-chemical analysis of metakaolin, microsilica and wollastonite included X-ray fluorescence 203
(XRF), X-ray diffraction (XRD, thermogravimetry (TG), differential thermal analysis (DTA, SEM, 204
EDX and high-resolution 29Si MAS NMR. The potassium silicate composition was determined by 205
XRF. Details of sample preparation and complete results can be found in Paiva (2008). 206
Geopolymers cured for mechanical tests were also sampled for physical-chemical characterization 207
by XRD, FTIR, TG, DTA, SEM, 29Si MAS NMR, 1H NMR, differential scanning calorimetry 208
(DSC) and thermomechanical analysis (TMA). 209
2.3 Standard well cement tests 210
Conventional and geopolymer slurries were prepared and tested according to API RP 10B-2 (2013) 211
for rheology, free water, fluid loss, and thickening time determination. . The flow curve was 212
measured using a Chandler Model 3506 Viscometer and the results were interpreted using the 213
Bingham model. Fluid loss was obtained in a Fann Fluid Loss Tester. Thickening time was 214
determined using a Chandler Model 8340 HPHT Consistometer. The bottom hole static temperature 215
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(BHST) was calculated for a model well 530 m [1740 ft] deep, using a geothermal gradient of 216
4.2°C/100 m [2.3°F/100 ft], obtaining 49°C [120°F]. The calculated circulating temperature 217
(BHCT) is 31°C [86°F]. The temperature and pressure schedule was calculated according to API 218
RP 10B-2 (2013). 219
2.4 Mechanical tests 220
Slurries were placed in cylindrical molds of 5.0 cm [2.0 in] diameter and 10 cm [3.9 in] height. 221
Geopolymers were insulated with PVC film to prevent drying shrinkage (Tavares et al., 2004). All 222
samples were cured in a wet chamber for 14 days at 49ºC [120ºF] and atmospheric pressure, except 223
for those labeled with the suffix B (P3.B, P4.B and P5.B), which were pre-cured at 10 MPa 224
[1450 psi] and 49ºC [120ºF] for 48 h before being moved to the wet chamber for the remaining 12 225
days. 226
For each formulation, three samples were tested in uniaxial compression according to ASTM C39 227
(2016) at 0.1 mm/min [3.9 mils/min]. Compressive tests were instrumented with axial LVDTs. 228
Poisson ratios were determined using axial and lateral strain gauges. Nine samples were tested in 229
triaxial compression (ASTM D2664-04, 2004) at 2, 6 and 10 MPa [290, 870 and 1450 psi] 230
confining pressures, using three samples per pressure. Indirect tensile strength tests (ISRM, 2014) 231
were performed at 0.8 mm/min [31.5 mils/min] in four samples per formulation. 232
3 NUMERICAL 233
Simulations were performed in five selected transverse sections of a 500 m [1640 ft] vertical well, 234
as shown in Fig. 1. The well has a 0.1778 m [7 in] casing of nominal weight 340 N/m [23 ppf], 235
placed on a 0.2223 m [8 3/4 in] circular hole with a 70% stand-off and cemented to the surface with 236
the given cement paste, with industrial water inside the casing. Fig. 2 shows a well section and a 237
detail of the 2D plane strain finite element mesh employed, with 9353 nodes and 3040 elements. 238
Tripling the number of elements in the cement sheath, casing and 1.5 m of surrounding rock 239
changed the failure temperature by less than 0.1°C, so further mesh refinement was not necessary. 240
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All elements are coupled temperature-displacement 8-node quadrilaterals, with biquadratic 241
displacement, bilinear temperature and reduced integration. The formation is a circular section with 242
50 m [164 ft] radius, mechanically pinned and kept at constant temperature at the far end. 243
244
Fig. 1 – Well geometry, formations and depths of the simulated sections. At 200 m, the same section 245 is simulated with both formations. 246
247
Fig. 2 – Detail of the geometry and finite element mesh of a 2D well section (eccentric casing, 248 cement sheath and formation). The problem is symmetric around the vertical axis. There are 240 249 elements in the casing and 400 in the cement sheath. 250
Steel and rock are modeled as linear elastic, while the cement or geopolymer is elastoplastic with a 251
Mohr-Coulomb failure criterion and a Rankine (maximum principal stress) criterion in tension. 252
Table 2 summarizes the material properties adopted in the model. Pressures are equilibrated 253
radially with the gradient of water inside the casing and the gradient of slurry at the casing-cement 254
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and cement-rock interfaces. The initial stress state of the paste is the hydrostatic pressure after 255
placement. The initial temperature is uniform, calculated from the geothermal gradient. 256
Table 2 – Material properties used in thermomechanical simulations. Mechanical properties 257 measured in this work are listed in Table 6. 258
Property Units Steel Carbonate Sandstone P2 P3, P4, P5
Young modulus GPa [ksi]
200 [2900]
7.0 [1015]
3.43 [497]
Poisson ratio 0.30 0.23 0.28
Specific heat kJ/m3 ºC 4000 2000 2788 2200 1750
Thermal conductivity W/m ºC 15 2.4 1.59 0.7 0.3
Thermal expansion 10-5/ºC [10-5/°F]
1.16 [0.644]
0.80 [0.444]
1.0 [0.555]
1.38 [0.767]
0.40 [0.222]
Density kg/m3 [ppg]
7854 [65.5]
2560 [21.3]
2220 [18.5]
1799 [15.0]
1700 [14.2]
259
Steam injection was idealized by heating to 260°C [500°F] at 110°C/h [198°F/h] and ramping the 260
internal pressure at the inside of the casing to the pressure of saturated steam at this temperature 261
(4.59 MPa [665 psi]) in 10 minutes. 262
During heating, the cement or geopolymer sheath is monitored for plastic strain, caused by violation 263
of one or more failure criteria. If the material fails, the current temperature and failure mode is 264
recorded. 265
4 RESULTS AND DISCUSSION 266
4.1 Characterization 267
Chemical composition of the materials was determined by FRX and crystallinity was assessed by 268
XRD. Metakaolin is 95 wt. % aluminosilicate (49.3 wt. % alumina and 45.7 wt. % silica), with an 269
amorphous hump located between 20° and 30° 2θ and quartz (PDF 00=046-1045) and kaolinite 270
(PDF 00-014-0164) as crystalline contaminants (Fig. 3). Microsilica is 95.9 wt. % amorphous 271
silica (Fig. 4). Wollastonite is 97.8 wt. % crystalline calcium silicate hydrate (PDF 00-043-1460) 272
(Fig. 5). The commercial silicate solution contains 37.8 wt. % potassium silicate (26.7 wt. % K2O 273
and 11.1 wt. % SiO2) in aqueous solution. 274
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275 Fig. 3 – XRD patterns of the two batches of metakaolin used in the study. 276
277 Fig. 4 – XRD pattern of microsilica 278
279
Quartz
Kaolinite (C)
RJ
RN
Angle (2θ)
Angle (2θ)
Angle (2θ)
Wollastonite
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Fig. 5 – XRD pattern of wollastonite. 280
281
Thermal analysis (Fig. 6) shows that the materials are thermally stable up to 600°C. Metakaolin and 282
microsilica lose about 5% of their mass, gradually over the whole interval analyzed, suggesting 283
dehydration of adsorbed water for microsilica and metakaolin up to 200°C, and dehydroxylation of 284
kaolinite from 400°C to 500°C. 285
286
Fig. 6 – Thermogravimetric analysis of raw materials. 287
288
Scanning electron microscopy images (Fig. 7) shows that metakaolin and microsilica are composed 289
of approximately spherical particles consistent with the size distribution measured by laser 290
granulometry (not shown). Wollastonite has an acicular geometry, with fibers about 100 µm long. 291
EDX analysis confirms the homogeneity and overall composition determined by FRX. 292
Metakaolin Microsilica Wollastonite
Wei
ght
Loss
(T
G, %
)
Temperature (oC) D
TG
(%
/sec
)
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1000x/ 10 µm
128 x 128 pixels
(a) Metakaolin (Al ���� red and Si ���� blue). 293
294
1000x/ 10 µm
128 x 128 pixels
(b) Microsilica (Si ���� blue and O ���� green). 295
296
1000x/ 10 µm
128 x 128 pixels
(c) Wollastonite (Si ���� blue and Ca ���� yellow) 297
298
Fig. 7 – SEM and EDX of raw materials. 299
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300
Fig. 8 displays the 29Si MAS NMR spectra of the original materials. Metakaolin shows Q4(m Al) 301
silicates, with a peak at -91.6 ppm corresponding to kaolinite (Q3 silicates). Microsilica presents a 302
main peak at -110.5 ppm (Q4 silicates), with contributions from Q3, Q2 and Q4(m Al) groups. 303
Wollastonite displays Q2 silicates. 304
305 Fig. 8 – 29Si MAS NMR spectra of raw materials. 306
4.2 Geopolymer characterization 307
X-ray diffraction patterns of the geopolymer formulations show an amorphous hump centered 308
around 29°, shifted from the humps observed in both metakaolin and microsilica patterns. Weak 309
quartz and kaolinite peaks were observed in some samples. P5 displayed small wollastonite peaks, 310
consistent with the pattern of that material and with the small fraction of fibers in the formulation. 311
This is evidence that a similar microstructure was obtained using microsilica as an alternative 312
source of silica. Pre-curing at 10 MPa [1450 psi] for 48 h did not change the patterns, with 313
exception of spurious peaks at around 40° 2θ for P4 and 45° 2θ for P5.B probably related to 314
Wollastonite
Microsilica
Metakaolin
Chemical deviation (ppm)
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samples contamination, showing that pressure levels representative of downhole conditions do not 315
change the geopolymer structure. 316
317
318
Angle (2θ)
Angle (2θ)
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319
Fig. 9 – XRD diffractograms of geopolymer pastes. 320
321
FTIR spectra (Fig. 10) are also very similar for all three geopolymer formulations, including those 322
cured under pressure, confirming that the same product was generated. The main absorbance peak is 323
located between 1010 cm-1 and 1030 cm-1, shifted from silica peaks observed in the original 324
materials, an evidence of Si–O–Al bond formation. Smaller peaks corresponding to silicate 325
tetrahedra, Si–O–Al and Si–O–Si stretching are also observed. A wide peak around 3350 cm-1 326
suggests that –OH groups remain in the structure. 327
Angle (2θ)
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328
329
Wave number (cm-1)
Tra
nsm
itanc
e (%
) T
rans
mita
nce (
%)
Wave number (cm-1)
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330
Fig. 10 – FTIR spectra of geopolymer pastes. 331
332
Thermogravimetric analysis (Fig. 11) identified approximately 7% mass loss before 100°C and 333
progressive loss until 900°C, up to about 15% mass loss. The percentage seems to be related to the 334
amount of water present in the geopolymer systems. DTA and DSC show an exothermal event 335
simultaneous with the initial loss before 100°C. Formulations with retarder lost about 2% of their 336
masses around 310°C, which can be attributed to the decomposition of the retarder, also observed in 337
the DTA and DSC curves (Fig. 11). 338
339
Tra
nsm
itanc
e (%
)
Wave number (cm-1)
Wei
ght
Loss
(T
G, %
)
DT
G (
%/s
ec)
Temperature (oC)
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340
341
Fig. 11 – TG, DTA, DSC of geopolymer pastes. 342
343
Thermomechanical analysis (Fig. 12) shows geometrical stability up to 100°C and significant 344
shrinkage (up to 6% at 600°C) above this. Formulations containing wollastonite displayed less 345
shrinkage (4.8% at 600°C). 346
Temperature (oC)
Temperature (oC)
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347
Fig. 12 – TMA of geopolymer pastes. 348
349
The authors interpret that most of the mass lost below 100°C is due to water evaporation in 350
macropores, which does not cause significant shrinkage, as suggested by Duxson et al. (2005). 351
Above 100°C, loss of water in micropores causes drying shrinkage due to capillary effects. Above 352
250°C, kaolin dehydroxylation causes further shrinkage. 353
Electron microscopy of fracture surfaces show a compact structure, compatible with a well-formed 354
geopolymer, with nanometer scale voids. This suggests that the Si/Al ratio was adequate and that 355
the defoamer prevented the formation of air bubbles. Formulation P5 displayed a larger number of 356
pores, which may be related to the presence of wollastonite fibers. These fibers were apparently 357
incorporated to the matrix. 358
Temperature (oC)
Len
gth
Var
iatio
n (%
)
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10000x / 1 µm
30000x / 500 nm (a) P3 359
10000x / 1 µm
30000x / 500 nm (b) P4 360
10000x / 1 µm
30000x / 500 nm (c) P5 361
Fig. 13 – SEM of geopolymer pastes. The lengths (µm and nm) correspond to the size of scale bar. 362
EDX imaging shows that Si, Al and K are uniformly distributed in the matrix. A few aluminum-rich 363
particles were embedded in the matrix, probably unreacted particles. Calcium oxide-rich fibers can 364
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be found in formulation P5. Pastes cured at 10 MPa [1450 psi] did not display qualitative changes 365
in the EDX images. 366
1000x / 10 µm
128 x 128 pixels
(a) P3 (Si � blue, Al � red and K � green). 367
1000x / 10 µm
128 x 128 pixels
(b) P4 (Si � blue, Al � red and K � green). 368
1000x / 10 µm
128 x 128 pixels
(c) P5 (Si � blue, Al � red and K � green) 369
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Fig. 14 – SEM and EDX of geopolymer pastes. The lengths (µm and nm) correspond to the size of 370
scale bar. 371
372
Hydrogen (1H-NMR) time domain analysis was performed to determine the relaxation time (T1). As 373
shown in Table 3, more than 80% of the relaxation occurs in the 0.1 to 0.6 ms range, and a 374
significant amount occurs in the 1 to 20 ms range. Samples with wollastonite (P5) displayed 375
additional relaxation in the 30 to 50 ms range. Faure and Rodts (2008) interpreted the higher time 376
range (30 to 150 ms) as corresponding to the interaction between pore water and pore surface. A 377
lower range (2 to 3 ms) was attributed to micro-organized water. These results suggest that most of 378
the water is in the form of –OH groups (lowest range) and micropore water (1 to 20 ms range). The 379
fraction in the 30 to 50 ms range, observed in formulation P5, may be related to the larger pores 380
observed by SEM. Larger relaxation times are absent, probably because the samples were dried 381
before testing. 382
Table 3 – Summary of 1H-NMR results. TCi and Ai are the spin-network relaxation times and 383 the corresponding fraction. Pn.B are geopolymers pre-cured with pressure. 384
Paste TC1 (ms) A1 (%) TC2 (ms) A2 (%) TC3 (ms) A3 (%)
P3 0.249 96.8 4.94 3.2
P3.B 0.533 85.5 1.60 14.5
P4 0.140 86.9 5.24 13.1
P4.B 0.243 92.8 13.4 7.2
P5 0.149 82.7 1.46 11.4 44.0 5.9
P5.B 0.168 82.1 1.16 14.1 30.0 3.8 385
Silicon (29Si MAS NMR) spectra are shown in Fig. 15 and quantified in Table 4. The samples are 386
generally similar: there are two main wide 29Si bands, the most intense of which is centered around 387
-92 ppm, corresponding to geopolymer silicates Q4(m Al) and some Q3. The other is centered 388
around -110 ppm and correspond to Q4(1Al) e Q4 silicates. According to Singh et al. (2005), the 389
latter do not strictly belong to the geopolymer, but Davidovits (1994b) observed a similar peak at -390
115 ppm when microsilica was added to the formulation. The fraction of geopolymer silicates 391
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increases when pre-curing with pressure. The base geopolymer P3/P3.B presents a weaker Q4(1Al) 392
band, which is also better resolved from the Q4 line. In these, a band from -60 ppm to -70 ppm 393
evidences Q0 or Q1 silicates, indicating low connectivity groups, which may be an unreacted 394
fraction of the potassium silicate solution. P4/P4.B have the largest fraction of geopolymer silicates. 395
396 Fig. 15 – 29Si MAS NMR spectra of geopolymers. Pn.B samples were pre-cured with pressure. 397
Table 4 - Quantitative 29Si MAS NMR interpretation. 398
Paste Q1 (%)
Q3 + Q4(3Al) + Q4(2Al) (%)
Q4(1Al) + Q4 (%)
Ratio
P3 5.6 63.9 30.5 2.1
P3.B - 76.3 23.7 3.2
P4 - 80.8 19.2 4.2
P4.B - 82.2 17.8 4.6
P5 - 67.8 32.2 2.1
P5.B - 78.0 22.0 3.5
399
4.3 Standard well cement tests 400
Results of API RP 10B-2 (2013) tests are summarized in Table 5. Slurry placement simulations 401
show that the rheology of geopolymer slurries is suitable for well cementing in the model scenario, 402
Chemical deviation (ppm)
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with an equivalent circulating density (ECD) compatible with the operational window, maintaining 403
usual displacement rates. Excessive filtrate loss (more than 100 mL/30 min) and free water (1 mL) 404
was observed for pure geopolymer (P3), but the addition of microsilica and consequent reduction of 405
the fluid content was sufficient to reduce the filtrate loss and free water of formulations P3 and P4. 406
If further control were required, Barlet-Gouedart et al. (2010a) suggests that Portland cement 407
additives can be effective in controlling filtrate loss and free water of geopolymers. 408
The base geopolymer P3 has a very short thickening time at the BHCT (31°C, 88°F), compared to 409
the operational requirement of three hours. This time was also very sensitive to temperature, being 410
less than half of the thickening time at room temperature (not reported). Unretarded versions of 411
geopolymers P4 and P5 had very similar results, as well as versions retarded with lignosulfonate-412
based additives (values not reported). However, the addition of the AMPS-based retarder to P4 and 413
P5 resulted in thickening time similar to that of the reference slurry (P2), as shown in Table 5. In all 414
cases, the consistency curve in Bearden units (Bc) shows a stable behavior with a right angle set 415
(less than 30 minutes between 50 Bc and 100 Bc). Based on the results of the standardized tests, we 416
can conclude that formulations P4 and P5 could be successfully pumped and placed in the intended 417
field operations. 418
Table 5 – API RP 10B-2 (2013) test results. 419
Slurry Temperature °C [ºF]
Plastic viscosity Pa.s [cP]
Yield stress Pa [lbf/100ft2]
Fluid loss cm3/30 min
Free water cm3
TT* min
P2 31 [88] 0.0674 [67.4] 5.84 [12.2] 59 0 218
P3 27 [80] 0.103 [103] 4.33 [120] 120 1.0 109
P4 31 [88] 0.140 [140] 17.0 [66] 66 0.5 210
P5 31 [88] 0.153 [153] 25.0 [92] 92 0.5 180 * Thickening time at the BHCT (31°C, 88°F)
420
4.4 Mechanical tests 421
Table 6 summarizes the mechanical properties measured in this work. Reference slurry P2 is 422
designed to be more compliant and deformable than a neat cement paste, but it is weaker in both 423
compression and tension. Latex allows the slurry to deform plastically before rupture, as shown in 424
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Fig. 16. The base geopolymer P3 is even more compliant, but its strength is lower than that of P2. 425
Addition of microsilica improves the compressive strength and increases the stiffness, while 426
wollastonite effectively increases the tensile strength, as observed by several authors (Silva, 2000; 427
Thaumaturgo and Silva, 1999; Silva and Thaumaturgo, 2003; Dias and Thaumaturgo, 2004; Zhang 428
et al. 2008). Even with fibers, failure of the geopolymers was always very brittle, as seen in Fig. 17 429
to Fig. 20. Curing at 10 MPa for 48 h had no significant effect on the mechanical properties. 430
Table 6 – Mechanical properties of cement (P2) and geopolymer (P3, P4 and P5) pastes. 431
Property Units P2 P3 P4 P5
Uniaxial compressive strength MPa [psi]
18.1 [2630]
17.4 [2520]
38.6 [5600]
37.4 [5420]
Young modulus GPa [ksi]
6.8 [986]
3.50 [508]
5.03 [730]
5.07 [735]
Poisson ratio 0.20 0.20 0.21 0.19
Friction angle ° 20.73 22.1 20.5 20.8
Cohesion MPa [psi]
5.86 [850]
7.33 [1060]
13.3 [1930]
13.3 [1930]
Tensile strength MPa [psi]
2.06 [299]
1.26 [183]
1.51 [219]
2.30 [336]
432
433
Fig. 16 – Stress-strain curves of triaxial compression tests on the reference paste P2. Strain values 434 are influenced by the compliance of the frame. Conversion: 1 MPa = 145 psi. 435
Strain
Str
ess
(MP
a)
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436
Fig. 17 – Stress-axial strain and stress-lateral strain curves of uniaxial compression tests on 437 geopolymer pastes. Conversion: 1 MPa = 145 psi. 438
Fig. 18 – Stress-strain curves of triaxial compression tests on the base geopolymer P3. Strain values are influenced by the compliance of the frame. Conversion: 1 MPa = 145 psi.
Strain
Str
ess
(MP
a)
Str
ess
(MP
a) S
tres
s (M
Pa)
Strain
Strain
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Fig. 19 – Stress-strain curves of triaxial compression tests on the geopolymer with microsilica P4. Strain values are influenced by the compliance of the frame. Conversion: 1 MPa = 145 psi.
Fig. 20 – Stress-strain curves of triaxial compression tests on the geopolymer with microsilica and mineral fiber P5. Strain values are influenced by the compliance of the frame. Conversion: 1 MPa = 145 psi.
4.5 Numerical Simulations 439
Steam injection causes the expansion of the casing against the cement or geopolymer and the 440
formation. For stiff formations (sections 1 and 2), the rock confines the material in the annulus, 441
inducing compressive stress states that could cause shear failure. All formulations were able to 442
resist these stresses and reach the final temperature, as shown in Table 7, but the geopolymers have 443
a wider safety margin due to their higher compressive strength. For this scenario, there is no risk of 444
failure with communication to the surface. 445
Compliant formations (sections 3 to 5) allow the cement sheath to expand, creating tensile stresses. 446
In the shallowest section (3), the initial hydrostatic pressure is insufficient to prevent tensile failure 447
of the sheath; therefore, all formulations fail in tension during heating. This translates to a risk of 448
zonal communication at shallow depths. 449
Base geopolymer P3 is the most compliant, thus generating the lowest tensile stress levels. This 450
explains why the formulation resists the highest temperature, even with the lowest tensile strength. 451
Formulations P4 and P5 have similar stiffness; therefore, the fiber addition is the determining factor 452
Str
ess
(MP
a)
Strain
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that allows P5 to withstand almost the same temperature as P2. The authors noticed that 453
geopolymers have lower heat conductivity and hold larger temperature gradients, resulting on a 454
secondary failure at section 4. 455
Table 7 – Failure temperature (when applicable) when heating to 260°C [500°F]. All failures 456 were tensile by radial cracking. 457
Section P2 P3 P4 P5
1. Carbonate at 150 m [492 ft] – – – –
2. Carbonate at 200 m [656 ft] – – – –
3. Sandstone at 200 m [656 ft] 170°C [339°F]
217°C [423°F]
150°C [302°F]
167°C [332°F]
4. Sandstone at 350 m [1148 ft] – – 225°C [438°F]
238°C [461°F]
5. Sandstone at 500 m [1640 ft] – – – – 458
5 SUMMARY AND CONCLUSIONS 459
In this work, the authors developed and tested three typical metakaolin-based geopolymer 460
formulations, a base geopolymer (P3), a geopolymer with microsilica (P4) and a geopolymer with 461
microsilica and mineral fiber (P5). Starting with ideal molar ratios and preliminary studies in the 462
literature (P3), we introduced an alternative source of silica, increasing the fraction of solids (P4) 463
and added fiber reinforcement (P5). From P3 to P5, we observed an increase in compressive 464
strength of 120%, in elastic modulus of 45% and in tensile strength of 80%, as well as a 20% 465
reduction in shrinkage. 466
Physical-chemical analysis by XRD, RMN, SEM and FTIR verified the quality of the source 467
materials and showed that the same compact and uniform geopolymer network was obtained, after 468
partial replacement of silicate by microsilica, due to care in preserving molar ratios, demonstrating 469
that microsilica contributed to the geopolymer matrix formation and that the fiber remained intact as 470
a reinforcement. 471
These formulations were subjected to a set of standard well cementing tests, demonstrating that P4 472
and P5 are suitable for field operations in the proposed scenario, replacing Portland-based slurry P2. 473
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The thickening time of the base geopolymer P3 is two short for operations, but the AMPS-based 474
setting retarder was effective for P4 and P5 at 31°C [88°F], increasing the thickening time from less 475
than two hours (P3) to three and a half hours (P4 and P5), a time comparable to the reference slurry 476
P2. 477
Mechanical tests show that compared to the reference cement paste P2, the base geopolymer P3 is 478
more compliant, but very brittle and weaker in tension. Addition of microsilica in P4 increased its 479
stiffness, while keeping it more compliant than P2, and improved significantly the compressive 480
strength. Mineral fibers in P5 improved the tensile strength with no detrimental side effects. All 481
geopolymer formulations were very brittle, while P2 was able to sustain significant deformation 482
before failure. This advantage is offset by the fact that P4 and P5 have more than twice the 483
compressive strength of P2, 10% higher tensile strength and 25% smaller stiffness. 484
Numerical simulations demonstrate that the best geopolymer is able to withstand injection 485
temperatures as high as the reference paste. The failure mode is strongly dependent on the initial 486
state of stress and on the stiffness of the formation. Compliant formations and low initial pressures 487
lead to tensile failures. Stiff formations tend to confine the cement sheath, changing the mode to 488
shear failure (microcracking in the case of P2, or brittle fracture for the geopolymers). 489
The main contribution of this work is a design workflow from fluid state properties to solid state 490
properties and, through numerical simulation, to the mechanical integrity over the life of the well. 491
This allows us to recommend these formulations for use in the field for this particular application, 492
grounded on solid experimental and numerical results. We suggest that more applications of 493
geopolymers in well cementing should be analyzed with this comprehensive methodology, 494
effectively integrating these alternative materials to the oil industry portfolio. 495
6 ACKNOWLEDGEMENTS 496
The authors acknowledge the support of Halliburton Services, which provided some of the chemical 497
additives used in the work, and the mechanical testing facilities of LABEST/COPPE/UFRJ. 498
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This work was supported by the National Agency for Petroleum, Natural Gas and Biofuels (ANP); 499
and Petrobras S.A. 500
Declarations of interest: none. 501
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613
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• AMPS-based setting retarder was effective at the temperature of this application
• New formulations are less stiff than the Portland-based reference
• Simulations show that resistance to steam injection is comparable to the reference