Control of Contained-Annulus Fluid Pressure Buildup

Abstract

Fluid trapped in the annulus of subsea wells can cause casing strings to fail. This condition occurs when casing annuli attain a closed-volume circumstance (when a well is cased, cemented, and head seals are set). During production, the heat transfer of the produced fluids to the casing strings causes the trapped fluid to increase in pressure. This condition is magnified in deepwater because annular fluids are cooler due to the cold deepwater environment. Laboratory testing indicates that thermal expansion of these fluids can cause trapped water- or oil-based fluids to increase in pressure above casing-collapse pressure, resulting in annular pressure buildup (APB). This paper outlines a simple laboratory procedure and resulting data to determine the resulting trapped-volume pressure. Data from eight fluid combinations are presented. The temperature change during testing is an increase from 80°F to 230°F. The testing relates to the conditions commonly found in deepwater Gulf of Mexico. The laboratory data obtained from this testing was used to design a spacer system for Walker Ridge 285 #1, a deepwater, subsea well located in the Gulf of Mexico. This paper also presents the job design and related procedure for the executed spacer system. Annular Pressure Buildup Introduction Cases of APB in annuli have been observed, documented, and reported for several years.1 On land, platform, and spar-type wells, the problem can usually be mitigated by bleeding off the annular pressure as required. However, subsea completions do not yet allow this option. Deepwater developments are extremely susceptible to APB when the differential between mudline temperatures and flowing-production temperatures exceeds 125° to 200°F. This increase in temperature significantly increases the pressure of a trapped volume of liquid. Laboratory testing shows that pressure increases exceeding 10,000 psi over placement pressure can be reached. In an actual well, the excessive pressure can cause casing and/or casing couplings to fail. The Definition of APB APB is the pressure generated by thermal expansion of trapped fluids as they are heated.2 When wellbore fluids heat up and expand in a closed system, the expansion causes high induced pressures. In most land and many offshore locations, this pressure may be bled off through surface-accessible wellhead equipment. In subsea completions, the primary annulus between the tubing and production casing (the A annulus) may be the only accessible annulus. Consequently, bleeding through the outer annuli (B, C, etc.) may not be possible. When a well experiences APB, two conditions are known to be present.3 First, a sealed annulus (or annuli) must exist. Commonly, a drilled formation is isolated in a cased well. Cement is circulated above the formation, and the top of cement (TOC) is frequently inside the annulus of the previous casing.3 When the wellhead is sealed, an isolated volume that is 100% liquid is created or trapped. Hence, the condition is termed as "trapped fluid" or "trapped fluid volume." Second, a temperature increase must occur. The trapped fluid will be heated by the drilling and production operations. When the fluid is heated by production, it expands and can produce a substantial pressure increase, which can be compounded if more than one annulus is sealed. Deepwater wells are likely to be vulnerable to APB because of the cold seafloor temperatures (approximately 40°F) at installation, in contrast to elevated subsea-wellhead temperatures that range from 180° to 200°F upon production. Various tools, such as casing design and temperature prediction programs, are available to evaluate APB.4,5 With the appropriate tools, steps can be taken to mitigate the risk associated with APB to help prevent casing failures. Common Mitigation Methods Existing solutions have been presented in past publications.6 Several of the following solutions are included in the literature:Cement shortfall (leave cement short of previous casing)Full-height cementing (cement filling the entire annulus)Preferred leak path or bleed port installation in previous casing stringSyntactic, crushable foam wrapEnhanced casing design (heavyweight and/or high-yield casing

Study on annular pressure buildup phenomenon in subsea wells considering the effect of cement

“…Their work indicated that at least 5% nitrogen is needed to mitigate APB. 19 Wang et al considered the change of the fluid properties with temperature and pressure in the proposed APB prediction model. The effect of the foamed spacer was also studied and a model was proposed to make the prediction when nitrogen exists.…”

“…10,12,13,15,16 However, the presence of cement has a nonignorable effect on casing deformation and affects APB indirectly, including the influence on annular temperature and casing pressure. Moreover, some wells with APB adopt a wellbore structure that makes the TOC below the previous casing shoe, 8,19,28 which is called "cement shortfall." An open-hole section of the formation is exposed in this structure to reduce fluid mass for relieving APB.…”

“…Besides, only a few researches provide basic experiments in sealed containers and the experimental F I G U R E 1 Offshore wellbore structure studies simulating actual annuli are insufficient. [19][20][21] In this paper, the effect of cement on APB is considered and a prediction model is proposed to analyze the APB phenomena. Laboratory experiments were also conducted with a radial full-size tri-annuli setup.…”

Estudo Do Efeito De Fluido Confinado Em Uma Caverna Salina

“…Indícios de correlação entre a pressão e a temperatura na cabeça do poço dado o fluxo de hidrocarbonetos (Fonte: Hasan et al, 2010) Comparação de modelos de APB (Fonte: Hasan et al, 2010) Yin e Gao et al (2014) propuseram melhorias em modelos já existentes na literatura ao considerarem a variação dos coeficientes de expansão térmica e compressibilidade dos fluidos anulares com a temperatura. Seguindo a linha deWilliamson et al (2003), devido à dificuldade de se obter propriedades termodinâmicas de fluidos de perfuração sintéticos, água de tratada foi usada para modelar a dependência de certos coeficientes com a temperatura, o que pode ser observado na Figura 12. Comparação de pressão em diferentes fluidos (Fonte:Williamson et al, 2003)…”

“…Seguindo a linha deWilliamson et al (2003), devido à dificuldade de se obter propriedades termodinâmicas de fluidos de perfuração sintéticos, água de tratada foi usada para modelar a dependência de certos coeficientes com a temperatura, o que pode ser observado na Figura 12. Comparação de pressão em diferentes fluidos (Fonte:Williamson et al, 2003)…”