Investigation of a Long-Term Cement Deterioration Under a High-Temperature, Sour Gas Downhole Environment

Abstract

The indiCat ions of cement deterioration at one of the greatest gas condensate fields in Pannonian basin (Croatia) was the motivation for research study carried out in order to investigate the possible involved mechanism of impairment. After almost 15 years of hydrocarbon production form naturally fractured carbonates, some wells begun to suffer of plugging across the perforated zone with unidentified debris, which was accompanied with water cut increase. This paper describes the laboratory evaluation of the actual environmental down hole impact (high reservoir temperature, BHST>180°C, sour gas: 22% CO2 and 150 ppm H2S) to the cement, as well as debris identification. The work indicated that oilwell cement under hostile down hole conditions after long-term exposure could be deteriorated loosing of compressive strength and its integrity. The dominant mechanism of cement deterioration is caused by CO2 corrosion process in the form of carbonic acid leaching. The CBL log data verified the cement disintegration behind 7-in. casing after 15 years of well production period. Introduction This paper is based on comparison of field, laboratory and published data in order to clarify the problem of impairment of well productivity at one of the greatest gas-condensate fields located in SW Pannonian basin (Drava River Depression) Croatia. More of 15 years of production history period for several wells (producing from naturally fractured carbonates) was characterized with some anomalies in terms of sharp water cut increase accompanied with building of an unidentified debris across the perforated zone. In order to investigate the occurred phenomena the research study was carried out judging the hypothesis about the cement deterioration as a cause of production failure. The conceivable mechanism of impairment was addressed to a long-term exposure of cement to the high temperature (BHST=180°C) and brine with sour gas (>20% CO2, 150 ppm H2S) environment. The problem of potential oilwell cement deterioration across the perforated zone, associated with various physico-chemical processes during, in most cases, decades of well service life was just sporadically considered in published petroleum engineering literature. The deterioration of neat Portland cement at temperature above 120°C has been known for many years. Same reports are suggesting original primary cement deterioration due to long-term contact to a particular formation water 1, especially at elevated (150–300°C) temperatures2,3,4. Studies on existing wellbore cement systems durability under geothermal conditions5,6,7 (BHT>250°C) verified that they may be deteriorated (loosing compressive strength and becoming permeable) in relatively short period of time6. The literature contains the detailed well documented information (based mostly on CO2 -EOR flooding studies) about carbonic acid corrosion in oil well cements3,8,9 as a dominant chemical process in wet CO2 environment—resulting with loss of compressive strength and structural integrity of cement sheath. This process, known as cement carbonation8,9 seemed to be the most likely the cause of cement deterioration in the studied particular case because of high CO2 content in production fluid gas-laden water and high reservoir temperature.

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

“…Generally, portlandite is attacked at faster rate and is the first to be completely leached out before C-S-H because it more reactive than C-S-H (Le Saout et al, 2004;Le Saout et al, 2006a, 2006bSantra et al, 2009;Brandl et al, 2011) . Field results of cement and rock samples retrieved from CO 2 injection wells confirm this phenomenon (Krilov et al, 2000;Carey et al, 2007;Mito et al, 2008;Scherer et al, 2011).…”

“…Initially, diffusion and reaction controlled carbonation plays the dominant role in compressive strength development (Bruckdorfer, 1986;Krilov et al, 2000;Barlèt-Gouédard et al, 2006;Kutchko et al, 2007;Barlèt-Gouédard et al, 2009;Santra et al, 2009;Lesti et al, 2013;Mason et al, 2013).…”

“…Limited studies (Krilov et al, 2000;Bois et al, 2013) have been conducted on cement degradation due to carbonic acid attack under HPHT conditions. In geothermal wells, for instance, temperature and pressure could be as high as 260°C…”

“…Temperature effect on degradation of well cement has been investigated previously (Saunders and Walker, 1954;Eilers et al, 1980;Krilov et al 2000;Fabienne et al 2002;Le Saout et al, 2006a, M A N U S C R I P T…”

Characterization of the unidirectional corrosion of oilwell cement exposed to H2S under high-sulfur gas reservoir conditions

“…The compressive strengths of the top section of the samples exposed in both the scenarios were much lower than that of the unexposed sample because the top section of the exposed samples were significantly corroded, consistent with previous studies. 1,24 Moreover, the compressive strength loss of the top section of the brine-exposed sample was about twice that of the gas-exposed sample because of the impact of the loose layer. The compressive strength of the middle section in the gas-exposed sample increased by 1.89%, whereas the compressive strength of middle section in the brine-exposed sample decreased by 7.08% as H 2 S attack had penetrated into this section.…”