Case Studies of Emulsion Behavior at Reservoir Conditions
- Sunil L. Kokal (Saudi Aramco) | Mohammed Al-Dokhi (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2008
- Document Type
- Journal Paper
- 312 - 317
- 2008. Society of Petroleum Engineers
- 1.2.3 Rock properties, 4.3.4 Scale, 4.1.5 Processing Equipment, 4.3 Flow Assurance, 5.1 Reservoir Characterisation, 5.2.1 Phase Behavior and PVT Measurements, 4.2.3 Materials and Corrosion, 4.2 Pipelines, Flowlines and Risers, 1.8 Formation Damage, 5.1.1 Exploration, Development, Structural Geology, 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics, 4.3.3 Aspaltenes, 1.4.3 Fines Migration
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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 facilities.
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.
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