Enhancing geopolymer cement self-healing property with elastomeric materials

Abstract

Geopolymer cement (GPC) is a promising oil and gas well cementing alternative to Ordinary Portland Cement (OPC). OPC forms ettringite, causing water absorption and shrinkage. GPC, with lower calcium content, is expected to have lower shrinkage. This study assesses GPC's performance with elastomeric expandable additive (R-additive), up to 25 wt.%. The mixing, rheological test, free water, compressive strength, and linear expansion test were done in accordance with American Petroleum Institute Recommended Practice 10. Results demonstrated that increasing R-additive concentration reduced slurry density. Additionally, rheological properties improved, with plastic viscosity increasing from 48 to 104 cP and the yield point from 3.8 to 12.3 N/m². The optimal R-additive concentration for ideal rheology was 20 wt.%. All formulations showed zero free water, while compressive strength and linear expansion (l/l₀) varied with curing time. The study also confirmed self-healing in geopolymer cement, preventing flow through the cement sheath at varying temperatures. A 25 wt.% R-additive concentration allowed successful pumping at 4.8 barrels per minute with 100 psi pumping pressure. In a nutshell, the inclusion of R-additive between 10 to 25 wt% into geopolymer cement meets the standards of the oil and gas industry and becomes the potential replacement for OPC.

Keywords:

• Fly ash
• self-healing
• geopolymer
• well cement
• elastomeric materials

Reviewing editor:

• Sanjay Kumar Shukla, Edith Cowan University, AUSTRALIA

Subjects:

• Mechanical Engineering
• Technology
• Mining, Mineral & Petroleum Engineering
• Civil, Environmental and Geotechnical Engineering
• Concrete & Cement; Waste & Recycling

1. Introduction

Current researchers look upon geopolymer cement (GPC) as an alternative to Ordinary Portland Cement (OPC) for oil and gas applications (Al Bakri Abdullah et al., 2012; Lemougna et al., 2016; Paiva et al., 2018; Pandey et al., 2012; Ridha et al., 2020; Ryu et al., 2013; Salehi et al., 2016; Wardhono, 2018). OPC is thought to be mechanically resistant when exposed to the high temperature and acidic environment of an oil well. On the other hand, studies by the number of researchers revealed that the OPC's structure had deteriorated when subjected to high temperatures, which is above 100 °C, and experienced strength reduction when exposed to an acidic and carbon dioxide (CO₂) rich environment (Nasvi et al., 2012; Ridha et al., 2016; Ridha et al., 2020). Another issue with OPC as an oil well cement is the volumetric shrinkage of the OPC slurry during hydration and hardening (Reddy et al., 2009; Santra et al., 2009). The issue led to the formation of microannulus cracks that resulted from the contraction of cement's external dimensions (Nasvi et al., 2014; Rahman et al., 2020) as well as de-bonding between the cement, casing, and formation (Broni-Bediako et al., 2016; Nagral et al., 2014). As a result, the migration of gas and liquid from the formation to the surface may occur (Richhariya et al., 2020; Ridha et al., 2018) which may lead to the catastrophic event, such as blow out.

The ettringite (Al₂Ca₆H₁₂O₂₄S₃) crystals that form in the hydrated OPC during the early phase of hydration as a result of the chemical reaction between calcium aluminate (CaAl₂O₄) and calcium sulfate (CaSO₄), both of which are present in OPC, absorb water and cause volumetric shrinkage of the cement slurry (Chenevert & Shrestha, 1991; Merlini et al., 2008; Salehi et al., 2017). Expandable additives act as a shape-memory agent can expand before cement setting, can be mixed together with the cement slurry to prevent the shrinkage (Broni-Bediako et al., 2016; Nagral et al., 2014). At the same time, the occurrence of volumetric shrinkage can be avoided as the expandible additive possible to seal the microannulus cracks post-cement hardening (Kiran et al., 2017; Rahman et al., 2021).

The remarkable difference between geopolymer cement and OPC is that geopolymer is made up of geopolymerization process; the alkaline activators, such as sodium silicate, sodium hydroxide activate the alumino-silicate binder to form a 3D polymeric chain consisting of Si-O-Al bonds (Barlet-Gouédard et al., 2007; Liteanu et al., 2009; Salehi et al., 2017). The water requirement in geopolymerization is not significant as compared to the hydration of OPC, thus the volumetric shrinkage in GPC is projected to be less than that of OPC (Salehi et al., 2017). Due to the low calcium concentration of the aluminosilicate source, the calcium content of GPC is also significantly lower than that of OPC. Contrarily, the high calcium content in OPC causes, over time, increases in porosity and permeability over time and results in loss in the mechanical strength and integrity of the cement sheath. The high calcium content in OPC causes the calcium ions that are present in calcium-silicate-hydrate (C-S-H) to be used up in carbonation reactions to form calcium carbonate (CaCO₃) (Zulkarnain et al., 2021). That is why, GPC will be more resistant to carbonation than OPC under conditions of high CO₂ exposure in CO₂-rich well settings due to its lower calcium concentration than OPC (Barlet-Gouédard et al., 2007; Nasvi et al., 2011; Uehara, 2010).

Other benefits of GPC's material properties over OPC, in addition to low shrinkage and resistance to carbonation, have been extensively studied in previous studies. These benefits include high mechanical strength, high pumpability, low permeability, low Young’s modulus, resistance to acid attacks, resistance to alkali-aggregate reaction, resistance to freeze-thaw cycles, stability at high temperatures, and tolerance to contamination with oil-based mud (Khalifeh et al., 2014; Rahman et al., 2021; Yang et al., 2009). Moreover, adopting GPC as an alternative to OPC offers a more affordable and environmentally friendly option because it requires less energy to manufacture, emits less carbon dioxide (0.184 tonnes per tonne of GPC generated vs. 1.0 tonnes per tonne of OPC produced), and costs less (He et al., 2019; Rahman et al., 2021; Yang et al., 2009).

In light of the limited research on the application of geopolymer cement for well cementing, as evidenced by a sparse body of studies (Barlet-Gouédard et al., 2007; Kiran et al., 2017; Liteanu et al., 2009; Rahman et al., 2021), this research seeks to contribute significantly to the field. The central focus of our study is to explore the impact of the elastomeric expandable additive (R-additive) on enhancing the performance of fly-ash-based strength-enhanced geopolymer cement (GPC) samples. By applying R-additive at various concentrations and subjecting the samples to curing at a temperature of 60 °C, we aim to investigate its influence comprehensively. Moreover, the introduction of slag cement into the GPC samples is intended to act as a strength enhancer in synergy with the R-additive. This study systematically examines key parameters including mixability, free water content, and slurry density. Additionally, we assess the nuanced effects of R-additive concentration on crucial properties, such as compressive strength, linear expansion, and fluid flow characteristics of the GPC samples. Through this research, we aim to not only fill a gap in existing literature but also provide valuable insights into optimizing the performance of geopolymer cement for well-cementing applications.

2. Materials and Methods

2.1. Materials

Geopolymer cement (GPC) was prepared using the fly ash Class F, following the ASTM C618-19 specifications (API, 2019c). Class F fly ash was obtained from the Tanjung Bin power plant in Johor, Malaysia. The reported total oxide content (SiO₂ + Al₂O₃ + Fe₂O₃) of Class F fly ash is above 50%, and CaO content is below 18%. The composition of the Class F fly ash is summarized in Table 1.

Table 1. The chemical composition of the Tanjung Bin fly ash.

Material	Chemical composition (%)
Class F fly ash	SiO2	Al2O3	Fe2O3	CaO	MgO	LOI	Other	Total
	46.47	25.95	8.31	6.88	4.95	1.61	5.83	100

The alkaline activators used in the study were Sodium hydroxide (NaOH) and sodium silicate (Na₂SiO₃). The NaOH was purchased from Merck KGaA in liquid form, with a concentration of 8 M. The Na₂SiO₃ on the other hand, was purchased from R&M Chemical and had a solids content ranging from 51 to 54 wt.%. To enhance the strength of the cement to obtain the desired strength range for well cementing, slag cement was added to the sample as a strength enhancer, with a concentration of 10% of the weight of the fly ash. Furthermore, R-additive, which is an elastomeric expandable additive that consists of styrene-butadiene rubber with a specific gravity of 0.945. Its purpose was to induce expansion in the cement while preventing volumetric shrinkage of the cement sample.

2.2. Methods

2.2.1. Preparation of GPC samples

A total of four formulations, namely R10, R15, R20, and R25, were prepared. All the formulations consisted of a solid blend comprising 65% of the mixture, which includes fly ash, slag cement, and R-additive. Additionally, 35% of the formulation was an alkaline-activator solution composed of 8M NaOH and Na₂SiO₃ in a ratio of 0.25 Na₂SiO₃ to NaOH. The concentrations of the R-additive were varied across the formulations. R10 contained 10% by weight of the solid blend, R15 contained 15%, R20 contained 20%, and R25 contained 25%. To maintain a fixed percentage of the solid blend at 65% by weight of the mixture, the concentrations of fly ash and slag cement were adjusted accordingly. Table 2 summarizes the specific adjustments made for each formulation.

Table 2. Concentrations of each constituent of the solid blend for each mix formulation.

Mix formulation	Concentration (% of solid blend)
	R-additive	Fly ash	Slag cement
R10	10	81.0	9.0
R15	15	76.5	8.5
R20	20	72.0	8.0
R25	25	67.5	7.5

Cement slurry with a 600 ml volume were prepared for each formulation. The slurry mixing process was carried out using the Constant Speed Mixer, Model 3260, developed by Ametek Chandler Engineering in Tulsa, OK, USA. Initially, the mixer was set to rotate at 4000 rpm for 15 s after pouring in all the solid constituents. Subsequently, the rotational speed was increased to a final value of 12,000 rpm for 35 s. The mixing procedure followed the guidelines outlined in API RP 10B-2 (API, 2019a), which also specified the procedures for conducting free water and rheology tests on the slurry.

The density of the slurry plays a crucial role in controlling the pumping of the slurry through the wellbore. During operations, the adopted density value is the equivalent circulating density (ECD), which combines the density of the slurry and the annular pressure loss. In this research, the density (ρ) of the slurry sample was measured in g/cm³ using a pressurized mud balance.

The free water test was conducted by pouring the slurry into a 250 ml measuring cylinder and then leaving the slurry undisturbed for two (2) hours. Subsequently, the water that was present on top of the cement was collected to determine the amount of free water.

The rheological properties of the slurry were measured using the Atmospheric Rheometer of Model 35 manufactured by Fann Instrument Company (Houston, TX, USA). Kinematic viscosity (v) was recorded at rotational speeds of 100 and 300 rpm and averages of five readings were taken for each rotational speed to calculate plastic viscosity (PV) and yield point (YP) as per Equations (1)(1) $$\mathit{\text{PV}}=(v_{300}-v_{100})\times 1.5$$(1) and (2)(2) $$\mathit{\text{YP}}=v_{300}-\mathit{\text{PV}}$$(2) . (1) $$\mathit{\text{PV}}=(v_{300}-v_{100})\times 1.5$$(1) (2) $$\mathit{\text{YP}}=v_{300}-\mathit{\text{PV}}$$(2)

Where PV is the plastic viscosity measured in cP, YP is the yield point measured in N/m², and v100 and v300 are the kinematic viscosities at 100 and 300 rpm measured in cP.

2.2.2. Measurement of compressive strength and linear expansion of GPC samples

Cube samples of GPC with dimensions of 2-inch × 2-inch × 2-inch for each formulation were casted and cured at the temperature of 60 °C in a water bath at atmospheric pressure. Measurements were taken for compressive strength and linear expansion on the samples that underwent various curing durations: 1, 14, 30, and 60 days. The compressive strength measurements followed the guidelines outlined in API SPEC 10A (API, 2019b), utilizing a Model 4207D Digital Compressive Strength Tester manufactured by Ametek Chandler Engineering (Tulsa, OK, USA). The compressive strength (F) of the samples was determined using Equation (3)(3) $$P=F/A$$(3) . (3) $$P=F/A$$(3)

Where P is the compressive strength measured in Pa, F is the compressive load at the point of failure measured in N, A is the cross-sectional surface area of the sample measured in m².

The procedure outlined in API RP10B-5 (API, 2019c) was followed to measure linear expansion. An expansion cell, as defined by Equation (4)(4) $$\Delta l/l_0=\left(\left(L_f-L_i\right)\mathrm{\times }0.358\right)/L_i\mathrm{\times }100\%$$(4) , was utilized for this purpose. The slurry was subjected to conditioning for 30 min and then poured into the expansion cell. The distance between the two steel balls of the cell before expansion was recorded as the initial length (L_i). Subsequently, the cell was placed into the water bath that was pre-heated at 60 °C and cured for a pre-determined curing time. After curing, the cell was removed from the water bath, and the distance between the two steel balls after expansion was recorded as the final length (L_f) (Rahman et al., 2020). (4) $$\Delta l/l_0=\left(\left(L_f-L_i\right)\mathrm{\times }0.358\right)/L_i\mathrm{\times }100\%$$(4)

Where Δl/l₀ is the linear expansion measured by percentage; L_f is the final length measured in mm, and L_i is the initial length measured in mm.

2.2.3. Fluid flow test and 3D images

A fluid flow test was conducted to preliminary provide the proof of concept for the self-healing technique. This test does not belong to API and was conducted as an additional test to the API testing through core flood equipment. In this test, brine water flowed through the cracked cement samples at the selected test temperature. The cracked cement plug was inserted inside the Hasler sleeve. The brine or hydrocarbon oil was injected from point A at a selected constant rate of 0.5 ml/min, and the effluent exit from point B was collected, as shown in Figure 1. The test was conducted until no more effluent was collected at point B. The amount of effluent collected for every 5 min and the cumulated effluent weight (weight of water collected in grams) vs. time were recorded.

Figure 1. Coreflood test setup.

3. Results and discussion

3.1. Mixability, amount of free water, and density of GPC slurries

In Figure 2, the correlation between density and concentration of R-additive is depicted. The results demonstrate that all formulations exhibited similar mixability and homogeneity, remaining stable during the mixing process. Additionally, no free water was observed in any of the formulations. Analysis of the density measurements indicated that as the concentration of R-additive increased from 10 to 15, 20, and 25%, the density of the slurry decreased from 1.76 to 1.74, 1.66, and 1.64 g/cm³. Notably, the most significant reduction in density, from 1.74 to 1.66 g/cm³, occurred when the concentration of R-additive was increased from 15 to 20%.

Figure 2. Density of GPC slurry at varying concentration of R-additive.

3.2. Rheological properties of GPC slurries

Figure 3 illustrates the Plastic Viscosity (PV) of GPC slurry at different concentrations of R-additive. The results demonstrate that higher concentrations of R-additive lead to increased rheological properties of the slurry, including PV and Yield Point (YP). Specifically, when the R-additive concentration was raised from 10 to 15, 20, and 25%, the PV values increased from 48 to 74, 83, and 104 cP, respectively. However, it is worth noting that maintaining PV below 100 cP is advisable due to pumpability challenges, as discussed by Igbani et al. (2020) and Zahid et al. (2018). Therefore, it is recommended to use R-additive concentrations below 20%.

Figure 3. Plastic viscosity (PV) of GPC slurry at varying concentration of R-additive.

The effect of increasing R-additive concentration on YP is depicted in Figure 4. When the R-additive concentration was raised from 10 to 15, 20, and 25%, the YP values increased from 3.8 to 6.7, 10.1, and 12.3 N/m², respectively. These results align with the findings of Richhariya et al. (2020), who studied the impact of dual-coated polyacrylamide (DPAM) as an additive. They concluded that higher PV values were attributed to the gelation properties of the slurry and that an optimal concentration of 16% DPAM resulted in the desired rheological characteristics. Further additions of DPAM beyond 16% did not exhibit significant variations in PV.

Figure 4. Yield Point (YP) of GPC slurry at varying concentration of R-additive.

3.3. Compressive strength of GPC samples

Figure 5 illustrates the relationship between curing time and the compressive strength (P) of GPC samples. The results indicate that increasing the duration of curing led to higher values of F and Δl/l₀, with varying gradients observed over periods of 1, 14, 30, and 60 days. Notably, Figure 5 demonstrates that the R10 formulation attained the highest P value of 15 MPa (2177 psi). Conversely, Figure 6 highlights that R20 and R25 achieved the greatest Δl/l₀ value of 0.7625%. Across all formulations, P and Δl/l₀ consistently increased as the curing period extended from 1 to 60 days, as summarized below:

Figure 5. Compressive strength (P) of GPC samples at varying curing time.

Figure 6. Linear expansion (Δl/l₀) of GPC samples at varying curing time.

• R10: P increased from 4.71 MPa (683 psi) to 2177 psi and Δl/l₀ increased from 0.3508 to 0.5213% as per Figures 5 and 6, respectively.

• R15: P increased from 6 MPa (871 psi) to 10.49 MPa (1522 psi) and Δl/l₀ increased from 0.1432 to 0.3101% as per Figures 5 and 6, respectively.

• R20: P increased from 5.14 MPa (745 psi) to 10.82 MPa (1569 psi) and Δl/l₀ increased from 0.7625 to 0.9903%, as per Figures 5 and 6, respectively.

• R25: P increased from 1.72 MPa (249 psi) to 10.33 MPa (1498 psi) and Δl/l₀ increased from 0.7625 to 0.9985%, as per Figures 5 and 6, respectively.

Figures 7 and 8 illustrate the impact of increasing the concentration of R-additive on P and Δl/l₀ for samples cured over different time periods (1, 14, 30, and 60 days). With the exception of the 1-day cured samples, P decreased as the concentration of R-additive increased across all other samples. By referring to Figure 7, it can be observed that when the concentration of R-additive was raised from 10 to 15%, P increased for the 1-day cured samples, remained constant for the 14-day cured samples, and exhibited a significant decline for the 30 and 60-day cured samples. Conversely, Figure 8 demonstrates that Δl/l₀ decreased as the concentration of R-additive increased from 10 to 15%. Subsequently, as the concentration of R-additive was further increased from 15 to 20%, l/l₀ showed a steeper decline compared to the previous decrease. However, the change in l/l₀ resulting from an additional addition of R-additive from 20 to 25% was negligible.

Figure 7. Compressive strength (F) of GPC samples at varying concentration of R-additive.

Figure 8. Linear expansion (Δl/l₀) of GPC samples at varying concentration of R-additive.

The formulations employed in this study, namely R10, R15, R20, and R25, were specifically tailored to suit the requirements of the oil and gas industry and aligned with the recommendations put forth by Abbas et al. (2013), Broni-Bediako et al. (2016), Mao et al. (2020), and Richhariya et al. (2020). Before finalizing the formulations that fulfilled the API criteria, several trial mixes were formulated and evaluated. In Figure 9, the failure modes of the samples during compressive strength testing are illustrated, revealing that the samples did not undergo complete crushing upon reaching the ultimate load. Consequently, the samples exhibited the ability to bear the load even after experiencing cracking.

Figure 9. Failure mode of the samples subjected to compressive strength tests.

3.4. Fluid flow test and 3D images

The cracked cement plug using elastomer at 25% (R25) was selected and used for this study and was inserted into the Hasler sleeve. The amount of effluent collected every 5 min and the cumulative weight of the collected water (measured in grams) over time were plotted in Figures 10 and 11, respectively. The injection fluid was maintained at a constant rate of 0.5 ml/min, and the maximum differential pressure was monitored to ensure it did not exceed 1500 psi, which is the compressive strength limit.

Figure 10. Brine effluent collected at 27 °C.

Figure 11. Cumulative brine effluent collected at 27 °C.

In the first 100 min of the test, the amount of effluent collected increased gradually, ranging from 0.5 to 3.5 g. It remained constant for the next 300 min before decreasing to zero after 450 min. The cumulative weight of water collected over time, as shown in Figure 11, remained stable after the 450-min mark. This indicates that the self-healing process effectively prevented flow through the cement sheath.

Another test was conducted using preheated brine and a preheated cement sample, both maintained at a temperature of 60 °C before the test. The effluent collected and the cumulative effluent were plotted in Figures 12 and 13, respectively. The results demonstrated that temperature had a significant impact on the self-healing acceleration process in the cement sheath. The time required for self-healing decreased from 410 min at 27 °C (Figure 11) to 310 min at 60 °C (Figure 13). This finding aligns with a study conducted by Reddy et al. (2009), which highlighted the role of higher temperatures in accelerating the self-healing process.

Figure 12. Brine effluent collected at 60 °C.

Figure 13. Cumulative brine effluent collected at 60 °C.

Figures 14 and 15 depict the cumulative effluent of hydrocarbon oil preheated to 60 °C. The effluent collected during the first 50 min of the test increased, followed by a period of constant effluent for the next 110 min. It then decreased to zero after 175 min, indicating a nearly 50% shorter time compared to the brine fluid test. The reaction of hydrocarbon oil in healing gaps or cracks in the cement sheath was observed to be much faster than that of the brine fluid, similar to the results observed in the expansion or swellable test.

Figure 14. Hydrocarbon oil effluent collected at 60 °C.

Figure 15. Cumulative hydrocarbon oil effluent collected at 60 °C.

Preliminary or proof of core flow concept testing demonstrates that the inclusion of self-healing additives effectively seals cracks. Using 3D imaging, we can observe the pore within the cement sheath before and after the core flood testing, as depicted in Figures 16 and 17. To obtain a detailed view of the cement plug, we utilized a high-resolution Micro CT Scanner, capturing 3D images before and after fluid flow testing. The porosity area and flow path across the cement sheath are indicated in blue. Notably, the porosity measurement, expressed as a percentage, decreased from 15 to 4.2%, while the permeability measurement in millidarcy (mD) decreased from 2.83 to 0.4 mD in the cement samples.

Figure 16. Cracked cement samples before (left) and after (right) exposure to 60 °C brine.

Figure 17. Cracked cement samples before (left) and after (right) exposed to hydrocarbon at 60 °C.

For comparative purposes, Figures 18 and 19 show images of the original crack-free cement plug. In this scenario, the porosity and permeability measurements for design R25 are 3.16% and 0.28 mD, respectively. For design R20, the corresponding measurements are 4.78% and 0.2 mD.

Figure 18. 3D images of uncracked cement plug-design R25.

Figure 19. 3D images of uncracked cement plug-design R20.

3.5. Geopolymer cement field trial

The geopolymer cement slurry made up of fly ash, alkaline activator, and elastomer at 25% (R25) has been tested in the yard scale at the massive volume of 40 bbl. The rheology measurement has been taken at the surface and well condition and the results are presented in Figure 20. It was observed that the 300 rpm reading for both measurements are below 275 cp, while the readings for 3 rpm are above 5 cp. The PV and YP measurements resulted in 21.84 cp and 3.42 lb/100ft, respectively, which in the acceptable range as per previous researchers (Igbani et al., 2020; Zahid et al., 2018). At the same time, Figure 21 shows the 10-min gel strength for both surface and well conditions are 10 and 13 lb/100ft, respectively. The rheology and gel strength measurements for the geopolymer cement slurry are within acceptable range of the operating company standard.

Figure 20. Rheology measurement of R25 formulation at surface and well condition.

Figure 21. 10-Min gel strength measurement of R25 formulation at surface and well condition.

The geopolymer cement slurry was successfully pumped with the pumping rate of 4.8 barrel per minute as shown in Figure 22 with the pumping pressure of 0.69 MPa (100 psi). Meanwhile, the geopolymer cement slurry managed to achieve 7.76 MPa (1125 psi) in 24 h and 10.34 MPa (1500 psi) in 48 h for the destructive compressive strength test which passed the requirement for drilling the next hole section as required by the operating company (PETRONAS, 2016).

Figure 22. Pumping rate of R25 formulation.

4. Conclusions

The research study involved the production of fly ash-based strength-enhanced GPC samples utilizing slag cement as the strength enhancer. These samples were created with varying concentrations of R-additive and subjected to curing at 60 °C. Several parameters were investigated, including mixability, amount of free water, density of slurries, compressive strength, and linear expansion. All formulations exhibited stability during mixing and demonstrated satisfactory mixability and homogeneity. The collected data indicated that the presence of R-additive did not result in any free water. The slurry density decreased from 1.76 to 1.64 g/cm³ and the rheological characteristics increased as the concentration of R-additive increased from 10 to 25%. The PV rose from 48 to 104 cP and the YP increased from 3.8 to 12.3 N/m².

Based on the rheological properties, an optimal R-additive concentration of 20% was identified. The P and l/l₀ exhibited varying slopes as the cure time extended. The maximum P of 15 MPa (2177 psi) was reached when the R-additive concentration was 10%, whereas the highest l/l₀ of 0.7625% was obtained when the R-additive concentrations were between 20 and 25%. The flow test results demonstrated the efficacy of the self-healing process in preventing flow through the cement sheath, and the impact of temperature on the acceleration of this process was significant. The R25 formulation exhibited favorable properties for field conditions, as it was successfully pumped at a rate of 4.8 barrels per minute with a pumping pressure of 100 psi. Moreover, the formulations tested in this study, which included R-additive concentrations ranging from 10 to 25%, met the standards set by the oil and gas industry. Thus, this research significantly contributes to the practical advancement of geopolymer cement applications in the petroleum industry, particularly in well cementing.

The exploration of the elastomeric expandable additive (R-additive) and its influence on fly-ash-based strength-enhanced geopolymer cement (GPC) samples addresses a notable gap in current literature, offering valuable insights into optimizing cement formulations for enhanced performance in petroleum well environments. This research is poised to inform industry practices, offering a nuanced approach to designing geopolymer cement formulations tailored for the demanding conditions encountered in petroleum well operations. By establishing a foundation for improved cementing materials, this study paves the way for more resilient and efficient cementing practices, contributing to the overall integrity and longevity of petroleum well infrastructure. As the petroleum industry continues to evolve, the practical implications of this research are evident in its potential to enhance operational efficiency, reduce environmental impact, and ensure the long-term sustainability of well structures.

Acknowledgments

The authors are thankful to the technologists of Universiti Teknologi PETRONAS and PETRONAS Research Sdn. Bhd. for the commitment and support to carry out various activities related to experimental work in the laboratory.

Disclosure statement

No potential conflict of interest was reported by the author(s).

Data availability statement

All data used for this research is included in this manuscript.

Additional information

Funding

This research was funded by PETRONAS Research Sdn. Bhd., Malaysia, via project cost center 015MD0-064, as administered by the Research Management Centre of Universiti Teknologi PETRONAS, Malaysia, and the project cost center E.025.GST.02019.003, as per the record of PETRONAS Research Sdn. Bhd.

Notes on contributors

Siti Humairah A. Rahman

Dr. Siti Humairah Abd Rahman is currently working in management position at PETRONAS’ Research entity under Carbon Capture, Utilization, and Storage (CCUS) Department. The author has completed PhD from Universiti Teknologi PETRONAS (UTP) in Petroleum Engineering, majoring in Well Cementing. She did her first degree in Biochemical Engineering and obtained her Master’s degree in Chemical Engineering. Throughout her 20 years of experience in Oil and Gas industry, she cultivated a diverse range of experience from new technology development, scale up, consultation until commercialization of the technology, involve in forging mutually beneficial collaboration and strategic partnership alliance, negotiation and maximizing profitability from technology sales to the organization. Her area of interest includes but not limited to commercialization, CCUS and circular economy.

Afif Izwan Abd Hamid

Afif Izwan Abd Hamid is currently Research Scientist at Petroleum Engineering Department, Universiti Teknologi PETRONAS (UTP), Malaysia. He obtained his Bachelor’s degree in Petroleum Engineering, majoring in Drilling Engineering in 2015. He also earned his MSc in Petroleum Engineering at the same institution in 2018. His areas of interests are oilwell cementing, enhanced oil recovery, production enhancement and circular economy.

Nurul Nazmin Zulkarnain

Nurul Nazmin Zulkarnain works as a researcher at PETRONAS Research Sdn. Bhd. She earned her Bachelor's degree in Petroleum Engineering from Universiti Teknologi PETRONAS (UTP) in 2014, specializing in drilling engineering. Currently, she is pursuing her doctoral studies at the same university, concentrating on refining the calibration method for well cement measurement. Her interests encompass green technology, analytical chemistry, and well engineering.

Muhammad Aslam Md Yusof

Muhammad Aslam Md Yusof obtained a PhD in Petroleum Engineering from Universiti Teknologi PETRONAS (UTP), Perak, Malaysia and MEngSc in Petroleum Engineering from University of New South Wales, Australia. He is currently working as a lecturer/consultant in in Department of Petroleum Engineering at UTP. He has about than 12 years of experience in industry and academic. Currently, a member of the Centre of Research in Enhanced Oil recovery (COREOR), Institute of Hydrocarbon Recovery, UTP which effectively provide consultancy, professional training and focus research on formation damage, carbon sequestration and drilling fluid.