Most emulsion studies are conducted with depressurized crude/water samples.
Can emulsions form in the reservoir at high pressures and high temperatures?
Generally, the answer to this question is anecdotal. This paper provides a
unique method and new data from emulsion studies at high pressures and high
temperatures. Two case studies are presented in which emulsions were suspected
to be the cause of production challenges in several wells. The experiments were
conducted in a special visual pressure/volume/temperature (PVT) cell with the
capability of observing emulsion phase behavior at reservoir conditions. The
effects of several variables on emulsion behavior were investigated, including
shear, pressure, temperature, water cuts, and asphaltene-precipitation tendency
of the crude.
The first case study is in a field that produces tight emulsions. The
results of this study indicate that emulsions can form at reservoir conditions,
with mixing, especially if the crude has a tendency to precipitate asphaltenes.
The new data suggest that emulsion behavior is linked closely to the presence
of fine solids through in-situ dynamic precipitation of organic solids
(asphaltenes) and inorganic salts (scales) as well as through fines migration
in the reservoir. In the second case study, a series of emulsion tests was
performed on bottomhole and wellhead samples from several wells. The results
suggest that the emulsions are relatively loose at bottomhole conditions but
become progressively tighter with a reduction in pressure and temperature. The
tightness of the emulsions was linked to fine solids that stabilize them. These
include primarily calcite and sulfur-rich heavy hydrocarbons like asphaltenes,
with trace amounts of silicates (clays and/or fine-grained silica), iron-rich
precipitates, and barite.
Produced crude oil is generally commingled with water, which can cause a
number of challenges during oil production. Some of this water can form an
emulsion with the crude oil. Emulsions are difficult to treat and cause a
number of operational problems such as tripping of separation equipment in
gas/oil separating plants (GOSPs), productivity decline in wells, production of
off-specification crude oil, and creation of high pressure drops in flowlines.
Emulsions have to be treated to remove the dispersed water and associated
inorganic salts to meet crude specification for transportation, storage, and
export, and to reduce corrosion and catalyst poisoning in downstream processing
Emulsions can be encountered in almost all phases of oil production and
processing (Fig. 1): inside the reservoirs, wellbores, and wellheads; at
wet-crude-handling facilities; with transportation through pipelines; in crude
storage and during petroleum processing. The question that has received some
debate is the formation and nature of emulsions inside the reservoir and in the
wellbores at bottomhole conditions. In other words, can emulsions form inside
the reservoir? This paper provides a novel method and new data from emulsion
studies at high pressures and high temperatures. Two case studies are presented
in which emulsions were suspected to be the cause of production challenges in
several wells. The experiments were conducted in a special visual PVT cell with
the capability of observing emulsion phase behavior at reservoir conditions.
The effects of several variables on emulsion behavior were investigated,
including shear, pressure, temperature, watercuts, and asphaltene-precipitation
tendency of the crude. The properties of the crude oils for the two cases are
shown in Table 1.
There is very little work reported on petroleum-emulsion behavior at HP/HT
conditions (i.e., at reservoir conditions) (Kokal and Alvarez 2003; Kokal et
al. 2003). The bulk of the reported work has been conducted with depressurized
emulsion samples (Kokal 2006; Schramm 1992; Kilpatrick and Spiecker 2001;
Yarranton et al. 2000). One of the challenges in conducting HP/HT work with
emulsions has been the availability of (or lack of) equipment for handling
them. This paper describes a method that uses a PVT cell to study emulsion
behavior at HP/HT conditions.
© 2008. Society of Petroleum Engineers
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- Original manuscript received:
29 November 2006
- Meeting paper published:
11 March 2007
- Revised manuscript received:
30 September 2007
- Manuscript approved:
7 November 2007
- Version of record:
15 August 2008