Summary
Selecting an effective scale inhibitor for squeeze application at 170°C is
not a simple task. The traditional thermal-stability test of aging the chemical
in bulk is often perceived to be too harsh. This results in many promising
products being rejected because of their apparent degradation at temperature.
The alternative of conducting the aging test inside core materials, which is
more representative of the downhole conditions, is not a novel idea. However,
to date, no definitive data are available to substantiate such a process and
quantify the difference between the two methods. This is mainly because of the
difficulties and complexity in conducting such an experiment at a high
temperature over a long period of time. In this paper, the results from a
recent investigation are presented. We describe the detailed procedures of the
planning and execution stages, lessons learned, and pitfalls that must be
avoided. A scale inhibitor was aged with two different methods: one in bulk, as
commonly practiced in the industry, and one inside a sandstone core. The aging
period varied between 45 days for the bulk and 110 days for the last desorbed
sample from the core. The samples that were aged inside the core retained much
of their inhibition efficiency, while those aged by the traditional method
(bulk) lost nearly all their effectiveness. These results demonstrate clearly
that the conventional method of thermal aging in bulk is unrepresentative and
that the loss in performance can be quantified. A novel finding from this study
is the evidence of an unexpected relationship between desorption and inhibition
effectiveness. The findings from this study could have great impact on
selecting chemicals for high-temperature (HT) applications, even more so in
those environmentally sensitive regions where the use of "yellow"
(biodegradable) squeeze chemicals is mandatory. Many of these chemicals have
been rejected because of their apparent thermal degradation, which has now
proved to be unrepresentative.
Introduction
In November 2005, Statoil began production from the Kristin field. Kristin
is a high-pressure/high-temperature (HP/HT) gas/condensate field in the
Haltenbanken area of the Norwegian Sea (see Fig. 1). It has the highest
reservoir temperature (170°C) and pressure (911 bar) among the fields that
Statoil is operating currently. Producing by natural depletion and with the
formation water containing in excess of 2,500 ppm of calcium (Ca) and 900 ppm
of bicarbonate (see Table 1), downhole CaCO3 scale deposition has
been identified as one of the major production-related problems. From the early
development phase, an active program to qualify suitable scale-control
chemicals has been put in place, and it includes chemicals for squeeze
treatment, wellhead continuous injection, and dissolver. For the squeeze
chemicals alone, more than 110 products have been tested, 20 of which are
considered to be yellow according to environmental classification by the
Norwegian authority (Norwegian Petroleum Directorate 2002). Many of these were
rejected because of poor performance, but many more of them were discarded
because of their apparent thermal degradation at test conditions. This led us
to review the current practice in the oil industry for thermal aging of
chemicals and the validity of such results in the application in the field.
Most of the literature describing the thermal aging of squeeze chemicals was
published in 1995 and the years that followed (Collins 1995; Graham et al.
1998, 2000; Audibert and Argillier 1995; Dyer et al. 1999). The enormous
interest generated during this period was caused primarily by the Eastern
Trough Area Project (ETAP) cluster development that included fields with a
maximum downhole temperature of 180°C and a reservoir pressure of 885 bar. The
screening technique relied mostly on the aging of chemicals in a sealed
Teflon®-lined bomb over a period of 7 to 21 days. The extent of degradation was
measured by their relative performance with respect to the fresh products. In
these earlier studies, the focus was placed mostly on the effect of
carrier-brine composition, pH, and oxygen level. The main degradation
mechanisms were considered to be backbone scission and functional group
degradation that were caused by hydrolysis and a free radical attack. A good
overview of these mechanisms was presented in a recent publication (Kotlar et
al. 2006), in which a refined technique for sample preservation and oxygen
removal before the thermal-aging step was described.
Although this approach was considered to be a reasonable screening technique
for the different products, doubt remained whether this was truly
representative in the field because the chemical was not confined within a rock
matrix. A number of papers did describe thermal aging inside core materials,
where both outcrop sandstone (Graham et al. 1997, 2001a) and reservoir (Graham
et al. 2001b) plugs were used. Typically, a small core plug was first saturated
with the selected chemical and then the core was shut in at high temperature
for a period of time. The intended samples (i.e., chemical aged inside the
core) were collected afterward for comparative performance-tests. With a short
core, the pore volume (PV) would be small, typically 7 mL for a 1-in.-diameter,
3-in.-length core with 18% porosity. If performance tests were to be carried
out, these samples would need to be diluted many times. This would be limited
to those effluents that had a high-enough concentration [i.e., the first 1 to
15 PV (24 hours) of the post-flush]. This was a short time frame compared to
the actual squeeze life in the field. More importantly, the chemical that came
out from the core during this period would have been trapped, more so than if
they had been adsorbed. The degradation mechanism of the chemical molecules in
a physically trapped environment was obviously quite different from that being
hindered by a surface-binding interaction. Although yielding some results, such
an approach would overlook the most critical part of the degradation process
for a squeeze chemical (i.e., the combined effect of thermal aging and the
surface-retention mechanism). It is this combined effect on which the current
study focuses.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
12 January 2007
- Meeting paper published:
28 February 2007
- Revised manuscript received:
14 September 2007
- Manuscript approved:
9 October 2007
- Version of record:
15 August 2008
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