Oilwell Cement Durability

Noı̈k, Christine; Rivereau, Alain

doi:10.2118/56538-ms

Cited by 22 publications

(12 citation statements)

References 4 publications

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“…Temperatures within this range of tobermorite stability have been recommended as optimum curing temperatures to prevent strength retrogression during early curing stage (Saunders and Walker, 1954 (Hara et al, 1978;Nelson et al, 1981;Henmi and Kusachi, 1992;Merlino et al, 2001;Matsushita et al, 2004;Richardson, 2008;Churakov, 2009). Above 150 o C, a moderately permeable but strong calcium silicate hydrate phase, called xonotlite (C 6 S 6 H), is formed (Noik and Rivereau, 1999;Fabienne et al 2002;Brand et al, 2011). Truscottite, which is formed at about 215 o C, is a weaker but less permeable form of tobermorite and may transform to xonotlite in its stable form.…”

Section: A N U S C R I P Tmentioning

confidence: 99%

“…In addition to the C-S-H polymorphs above, other structural forms, including an amorphous gel phase, might be produced at different temperatures and C/S ratios. Their structure, mineralogy and relative weights are characterized using techniques such as Fourier Transform Infrared (FTIR), Scanning Electron Microscopy (SEM), X-Ray Diffraction (XRD) and Neutron Magnetic Resonance (NMR) (Noik and Rivereau, 1999;Fabienne et al 2002;Le Saout et al, 2004, 2006a, 2006bNeuville et al, 2012;Lesti et al, 2013).…”

Section: C-s-h (I) C-s-h (Ii)mentioning

confidence: 99%

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Investigating temperature effect on degradation of well cement in HPHT carbonic acid environment

Omosebi

Maheshwari

Ahmed

et al. 2015

Journal of Natural Gas Science and Engineering

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Section: A N U S C R I P Tmentioning

confidence: 99%

Section: C-s-h (I) C-s-h (Ii)mentioning

confidence: 99%

Investigating temperature effect on degradation of well cement in HPHT carbonic acid environment

Omosebi

Maheshwari

Ahmed

et al. 2015

Journal of Natural Gas Science and Engineering

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“…It was concluded that alternative cements have to be used to guarantee long term integrity for H 2 S injection wells. Noik and Rivereau (1999) designed a "reactive powder cement (RPC)" composed of API class G with sand and silica fume. The system mixed at 15.8 lbs/gal (ppg) had a low water:cement ratio of 0.27 resulting in low water permeability of less than 10 -6 mD after curing at 356 °F for 3 months.…”

Section: D Cement Corrosion Due To Dissolving Attackmentioning

confidence: 99%

Cementing Solutions for Corrosive Well Environments

Brandl¹,

Cutler²,

Seholm³

et al. 2010

Proceedings of International Oil and Gas Conference and Exhibition in China

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Main factors which are responsible for the corrosion of the cement sheath in wells are determined based on lab tests and field analyses from a literature survey. A description of the chemistry, mineralogy, physical properties of API well cements and their mechanisms of corrosion in the presence of aggressive formation and injection fluids (such as magnesia or sulfate containing brines and CO 2 ) are given. API cement hydration mainly produces Calcium-Silicate-Hydrate (C-S-H) phases, which are responsible for the strength, and portlandite "Ca(OH) 2 " which is basically a weak point within the cement matrix. Increasing permeability and portlandite content reduce strength and chemical resistance of set cement towards corrosive media. The addition of pozzolanic materials eliminates portlandite and allows lowering the water content in the cement system. Both effects can reduce the permeability and improve the mechanical properties of set cement. Cement specimens were prepared and exposed to CO 2 loaded water at 300 °F and 3,000 psi for 6 months. Mechanical properties tests, microscopy, and quantitative CaCO 3 analyses revealed significantly less corrosion and negative impacts for an API cement-pozzolan blend compared to a conventional API cement design at same density. Practical and economical concepts for improvements of the cement sheath with respect to cement slurry design, cementing process and the impact of factors such as temperature or cement admixtures are presented to mitigate cement corrosion. IntroductionWell cementing is a fundamental and essential part during the drilling of a well. The primary goals of the annular cement sheath in wells are zonal isolation, supporting the casings and protecting them from corrosion. The cement sheath must not only withstand downhole stresses induced by pressure and temperature fluctuations, but also corrosive attacks from aggressive formation and injection fluids (such as CO 2 flooding for enhanced oil recovery or "CO 2 capture and storage"). Cement sheath failures leading to loss of zonal isolation are the biggest concerns since they affect the wellbore integrity and so the life of the well with economical consequences: decline in production rates, loss of production time because of remedial cementing, and in worse case, even complete well failure/collapsing so that well abandonment is the last resort. Therefore it's imperative to design cement systems that counteract all negative impacts on the sheath integrity during the life of a well, to ensure maximum durability. Synthetic and epoxy resin-based binders provide high chemical resistance and good mechanical properties in the well (Cole 1979). Nevertheless, their extremely high costs limit their use to special applications. Calcium aluminate or phosphate based cements also proved to be more highly corrosion resistant than Portland cements (Sugama 2006). But these cements are sensitive towards contaminations with Portland cements and so must be handled separately requiring advanced planning which results in expensive log...

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“…Asimismo, también existen estudios sobre el ataque químico a cementos petroleros en condiciones de altas temperaturas y presencia de ácido sulfhí-drico en el yacimiento (8); mientras muy pocos son los trabajos que han estudiado el efecto combinado de ambos gases agrios sobre los citados cementos a altos valores de presión y temperatura (9).…”

Section: Introductionunclassified

“…Moreover, there are also works on the chemical attack on petroleum cements at high temperatures and in the presence of hydrogen sulfide in the reservoir (8). However, there are very studies on the combined effect of both sour gases on these cements at high pressure and temperature (9).…”

Section: Introductionmentioning

confidence: 99%

Ataque del anhídrido carbónico y el ácido sulfhídrico sobre pastas de cemento API clase H expuestas a aguas de formación salinas

Márquez¹,

Sánchez²,

Martín-del-Río³

et al. 2010

Mater. construcc.

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RESUMENSe simuló la acción agresiva de los denominados iones fundamentales (sulfato, cloruro y magnesio) y los gases agrios presentes en el gas natural (CO 2 y H 2 S) sobre un cemento API clase H utilizado en pozos gasíferos a presión y temperatura elevadas, al objeto de observar sus alteraciones fisicoquímicas por la acción combinada de tales gases y las aguas de formación. Se prepararon varias probetas del material cementante para su inmersión en disoluciones neutras, conteniendo los iones fundamentales en concentraciones fijas, dentro de reactores tipo Parr. Se analizaron durante más de dos meses una serie de disoluciones en contacto con el cemento utilizado; así como, mediante DRX, la evolución de la mineralogía de dicho material entre los 14 y los 60 días. Los principales efectos de ambos gases, en conjunto o por separado, sobre la durabilidad del cemento fueron, respectivamente, la formación de carbonato cálcico y la lixiviación de algunos componentes.Palabras clave: cementos para pozos de petróleo, durabilidad, pasta de cemento, difracción de rayos X, fases cristalinas. SUMMARYThis paper discusses the attack of the major ions (sulfate, chloride, and magnesium) and sour gases, present in natural gas (CO 2 y SH 2 ), on API class H cement, the type used in gas wells under high pressure and temperature. The effects of these chemical agents on this cement was simulated to study the physicochemical changes due to the action of sour gases and formation water. Cement specimens were immersed in neutral solutions containing fixed concentrations of the major ions inside Parr reactors. These solutions were analysed and XRD analyses were conducted for over two months to identify mineralogical variations from 14 to 60 days. The objective of this research was to determine the effects of the joint attack of major ions and sour gases on cement pastes. The main effects of both gases, jointly or separately, on cement durability were, respectively, the carbonation process and the leaching of some components.Keywords: petroleum wells cemen, durability, cement slurries, XRD , crystalline phases. INTRODUCCIÓNLos denominados gases agrios, anhídrido carbónico y ácido sulfhídrico, significativamente presentes en la mayoría de yacimientos de gas y petróleo (1), pueden provocar importantes cambios fisicoquímicos sobre el cemento colocado entre el revestidor de un pozo y las formaciones rocosas (2); dicho material cementante se deteriora con el tiempo al ser atacado por ambos gases, sobre todo en presencia de ciertos iones (sulfato, cloruro o magnesio) contenidos en concentraciones que superan los 40.000 ppm en las aguas de formación en contacto con el cemento (3). Las concentraciones del ácido sulfhídrico y anhídrido carbónico en el gas natural suelen arrojar valores no superiores al 10% y 30% molar, respectivamente (4). Los gases agrios se disuelven en medio acuoso produciendo una serie de iones (sulfuro, carbonato, etc.) que afectan significativamente a la durabilidad del cemento en los pozos de gas y petróleo, influyendo sobre l...

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Oilwell Cement Durability

Abstract: This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

Cited by 22 publications

References 4 publications

Investigating temperature effect on degradation of well cement in HPHT carbonic acid environment

Investigating temperature effect on degradation of well cement in HPHT carbonic acid environment

Cementing Solutions for Corrosive Well Environments

Ataque del anhídrido carbónico y el ácido sulfhídrico sobre pastas de cemento API clase H expuestas a aguas de formación salinas

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