Summary
Nonaqueous-drilling fluids are often chosen to drill troublesome shale
formations in an effort to minimize wellbore-instability problems. However,
experience in the Gulf of Mexico (GOM) indicates that when drilling in highly
faulted areas, oil- and synthetic-based fluids do not always prevent wellbore
destabilization. This is evidenced by wellbore collapse, and the resulting
difficulty with hole cleaning, tripping, logging, and casing running.
It is known that the chemical, physical, and mechanical effects resulting
from the interaction between the drilling fluid and the formation may degrade
the stability of the borehole in the already weakened and stressed fault
interval. Commonly, the practice has been to increase the drilling fluid’s salt
content to enhance the borehole stability. The perception that low
drilling-fluid water activity is beneficial to wellbore stability needs to be
revised.
A detailed laboratory investigation using preserved-shale core and drilling
information has confirmed that the water activity of drilling fluids is often
much lower than necessary. This study has shown that when drilling faulted or
fractured shale, the correct, not higher, salt content in drilling fluids will
reduce wellbore-collapse problems and improve drilling performance.
A laboratory method, which allows the quantitative measurement of water and
ion movement during shale/mud interactions, combined with geological
information optimizes the salinity design of drilling fluid, which controls
water and ion movement. Laboratory data and field cases from GOM drilling
support the concept of optimum salinity to enhance borehole stability in
naturally fractured formations as part of the stressed-shale-drilling strategy
to improve drilling performance.
Introduction
It is generally accepted that nonaqueous drilling fluids are superior to
water-based muds in improving wellbore stability in shale formations (Chenevert
1970; Salisbury and Deem 1990; Hale et al. 1992; Chenevert and Sharma 1993;
Simpson and Dearing 2000). However, some field cases in the GOM, Colombia, and
Canada have demonstrated that wellbore-instability problems still occurred even
when oil- or synthetic-based fluids were used, especially in fractured
formations (Santarelli et al. 1992; Rojas et al. 2006; Gallant et al. 2007;
Last et al. 1998).
It is well known that water fluxes into or out of the shale formation during
drilling are the key factor in controlling wellbore stability. Studies showed
that water absorption by shale formation altered the stress distribution,
reduced the strength, and, at the same time, changed the Young’s modulus of the
near-wellbore formation, which may potentially destabilize the wellbore (Hale
et al. 1992; Yew et al. 1990; Zhang et al. 2006). On the other hand,
dehydration causing pore-pressure decrease and strength increase is beneficial
to wellbore stability (Chenevert and Strassner 1975; Hale et al. 1992; Yu et
al. 2001; van Oort 2003). However, overdehydration results in fractures in the
near-wellbore formation and may also disturb wellbore stability (Mody and Hale
1993; Horsrud et al. 1998; Gomez and He 2006). Kelly (1968a; 1968b) argued that
water desorption in fractured shales may widen the fractures and destabilize
the wellbore. On the contrary, he suggested slight water adsorption may soften
the fracture surface and is necessary to stabilize wellbore (Kelly 1968a; Kelly
1968b).
In a fractured-shale formation, which is called stressed shale in this
paper, it is particularly important to control water movement because the
in-situ stresses are in a critical state. Any disturbance of the formation by
chemical or mechanical means could result in shale breaking and sliding into
the hole. Once the wellbore instability is initiated, it would be difficult to
stop (Kelly 1968a; Labenski et al. 2003). Santarelli et al. (1992) and Labenski
et al. (2003) discussed how to improve wellbore stability in fractured
formations by keeping mechanical balance. In this paper, we will focus on
maintaining chemical balance between shale formations and nonaqueous drilling
fluids to minimize wellbore-instability problems.
It is nearly impossible to maintain the chemical-potential balance between
shale formations and drilling fluids because of the difficulty in measuring the
chemical potential directly. Generally, we balance the water activity of the
nonaqueous fluids with the water activity of the formation to control water
movement so as to improve wellbore stability (Chenevert 1970; Chenevert and
Strassner 1975). Because it is difficult to balance water activity of shale
formations with drilling fluids exactly everywhere in a well because shale
water activity varies with depth and mineralogy (Lal 1999), we try to balance
the water activities of shale formations and drilling fluids at the problematic
locations.
In this paper, we will first discuss how to predict and measure the in-situ
water activity of both shale formations and nonaqueous drilling fluids. It is
determined that water activity is both temperature- and pressure-dependent.
Then, experimental studies on determining water and ion movement during
shale/mud interaction will be presented, and the application of the results
from these experimental studies on determining the water activity of nonaqueous
drilling fluids will be discussed. Case studies will also be demonstrated in
support of the arguments and recommendations.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
26 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
4 May 2008
- Manuscript approved:
11 May 2008
- Version of record:
10 December 2008
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