Risk and Remediation of Irreducible Casing Pressure at Petroleum Wells

Risk and Remediation of Irreducible Casing Pressure at Petroleum Wells

Andrew K. Wojtanowicz (Louisiana State University, USA)
DOI: 10.4018/978-1-4666-4777-0.ch008
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Oil well cement problems such as small cracks or channels may result in gas migration and lead to irreducible pressure at the casing head. Irreducible casing pressure also termed, Sustained Casing Pressure (SCP) is hazardous for a safe operation and the affected wells cannot be terminated without remedial operations. It is believed that even very small leaks might lead to continuous emissions of gas to the atmosphere. In the chapter, the author describes physical mechanisms of irreducible casing pressure and qualifies the associated risk by showing statistical data from the Gulf of Mexico and discussing the regulatory approach. This chapter also introduces a new approach to evaluate risk of casing pressure by computing a probable rate of atmospheric emissions from wells with failed casing heads resulting from excessive pressure. Also presented is a new method for assessing potential for self-plugging of such wells flowing wet gas as the gas migration channels could be plugged off by the condensate.
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Annular And Sustained Casing Pressures

Petroleum wells are usually constructed such that their casing–casing annuli do not experience abnormal pressures. The exception occurs in gas lifted wells where gas is injected into the production tubing–casing annulus. Annuli differ from other well components in that they are usually not the result of purposeful design. Rather, they are a consequence of the design of tubulars and the well construction process. Therefore, the ability of an annulus to withstand loads that occur on its components is (or should be) evaluated at the end of the design process.

The right figure in Figure 1 shows different kinds of annuli in a well bore (JIP, 2001). The primary annulus (Type I, or A) is formed by the production tubing and casing. It is bounded on the top and bottom by the wellbore seal assembly and completion hardware (including packers and seals) respectively. In addition, there may be an annular safety valve, gas lift valves and related equipment depending on the nature of the well.

Figure 1.

Simplified well schematic and types of annuli in a wellbore (Detail “A”)

The secondary (outer) annuli (B, C, etc.) can be of two kinds- Types II and III. The Type II annulus is formed by two adjacent casing strings. It is bounded at the top by the wellhead seal assembly and at the bottom by the cement. The cement top in this instance is above the shoe of the outer string of the annulus. The type III annulus is essentially similar, except that its bottom is open to the formation. The cement top lies below the shoe of the outer casing string, either by design or accident.

By definition (as well as design) an annulus is a sealed volume, and there should be no flow paths that cause migration of fluids into (from) the annulus from (into) its surroundings. In principle, given the annular configuration, all leak paths that can compromise its integrity should be identified. This identification is an integral part of the design process and is the basis for the diagnosis and management of sustained casing pressure (SCP), later in the life of the well.

The left figure in Figure 1 is a typical well completion showing the placement of cement to seal off the interior of various casing strings from the subsurface formations exposed by the drill bit (Bourgoyne et al., 1999). Ideally, the well should have pressure only on the production tubing. Pressure gauges on all of the casing strings should read zero if:

  • The well is allowed to come to a steady-state flowing condition, and

  • The effect of any liquid pressurization due to heating of the casing and completion fluids by the produced fluids is allowed to bleed off by opening a needle valve at the casing top.

Only a small volume of fluid would be bled off in order for the casing pressure to fall to atmospheric pressure if the pressure was caused by thermal expansion effects.

If the needle valve is closed and the well remains at the same steady-state condition, then the annular casing pressure should remain at zero. If the annular casing pressure returns when the needle valve is closed, then the casing is said to exhibit sustained casing pressure (SCP). In some cases the pressure can reach dangerously high values.

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