Summary
Two high-rate acid-gas injection wells were drilled in the LaBarge area of
Wyoming. These wells were designed for injection of up to 65 million
scf/D of a mixture of 65% H2S and 35% CO2. The
primary engineering challenges in well design, casing selection, and cementing
of the injection strings, along with the related operational challenges for
both wells, are discussed. Key drivers influencing zonal isolation,
salt-zone loading, casing, and centralizer selection are presented.
Casing selection was influenced by corrosive gas composition, high injection
rates, and the potential for salt-zone loading. The use of SM–2550
tubulars, heavy wall casing for the salt loading, handling requirements, and
centralizer selection are discussed.
The primary driver in cement design was resistance to CO2,
because past work has shown little H2S interaction with cement under
these well conditions. A discussion of the development of a high-alumina
cement system with low fluid loss to address CO2 resistance and long
liner length is coupled with the quality-control steps taken from the time of
manufacture of the specialty cement to the final placement in the well.
Also described is the development of an alternative portland cement system
in which sized particles are included to dilute the cement and reduce total
system permeability.
The unique engineering solutions resulted in operational challenges with
casing running, cementing materials, and equipment. A description of the
location problems and the steps taken to resolve the issues is included.
Introduction
The acid gas-injection wells were drilled as part of an overall gas-plant
debottlenecking. Plant throughput capacity was being increased by
converting the plant to acid-gas disposal by injection. The anticipated
waste gas stream was 65% H2S and 35% CO2. Design
volume for the wells was based upon the capacity of the plant plus adequate
backup. The maximum planned plant-waste capacity was 100 million scf/D,
with the initial target waste volume planned at 65 million scf/D per well.
The corrosive gas stream required the use of specialty materials, which
complicated casing selection, centralizer selection, and handling on
location. Casing design was further challenged by the potential presence
of a salt formation above the planned injection intervals.
Unique cementing solutions are required in a CO2
environment. The gas converts calcium silicates in portland cement to
calcium carbonate, causing the cement to have an increased permeability and to
be soluble in acid (Onan 1984; Bruckdorfer 1986; Mueller and Dillenbeck 1991;
Bull. ACN 007 067 656 1995; Krilov et al. 2000). CO2 flood
projects typically require routine acidizing to remove scale caused by water in
the gas stream. The acid could dissolve the converted cement sheath and
ultimately cause loss of containment in the annulus. The subject
wells are not part of a CO2 flood, nor does the gas stream contain
water, but CO2 resistance was considered integral to the design.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
10 November 2004
- Revised manuscript received:
9 January 2006
- Manuscript approved:
26 January 2006
- Version of record:
20 September 2006
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