Development and Field Use of a Novel Solvent/Water Emulsion for the Removal of Asphaltene Deposits in Fractured Carbonate Formations
- Stephen C. Lightford (Halliburton Intl. Inc.) | Enzo Pitoni (Eni Agip SpA) | Luca Mauri (Eni E&P) | Franco Armesi (Halliburton Energy Services Group)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2008
- Document Type
- Journal Paper
- 301 - 311
- 2008. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 3 Production and Well Operations, 1.6 Drilling Operations, 5.2.1 Phase Behavior and PVT Measurements, 3.2.2 Downhole intervention and remediation (including wireline and coiled tubing), 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.2 Pipelines, Flowlines and Risers, 4.3.4 Scale, 5.1 Reservoir Characterisation, 1.8 Formation Damage, 4.1.5 Processing Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.6.9 Coring, Fishing, 2.4.3 Sand/Solids Control, 5.8.5 Oil Sand, Oil Shale, Bitumen, 2.2.2 Perforating, 4.3.3 Aspaltenes
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The formation of asphaltene scale inside the tubing or in the reservoir is a common problem associated with crude oils in many parts of Italy and is common to the industry as whole. In Italy, regular treatments with coiled tubing or washing by bullheading are performed to re-establish production. While asphaltene inhibitors can be injected into the tubing string, asphaltenes can still create problems below the injection point and plug the perforations, formation pores, and/or natural-fracture-network systems.
There is a wide range of hydrocarbon-based solvents that have been used in the industry to remove asphaltenes. The more effective solvents have a low flash-point temperature, making them expensive and hazardous. In addition, these hydrocarbon-based solvents leave the formation in an oil-wet state after asphaltene removal instead of re-establishing the water-wet condition that acts as barrier to slow down the deposition of the asphaltene on the formation. This effect accelerates the redeposition of the asphaltene in the formation and increases the rate of the production decline, increasing the frequency of remedial treatments.
This paper describes the laboratory development and field application of a water/aromatic-solvent emulsion system that has been used successfully to clean/dissolve asphaltene and leave the carbonate fractured formation in a water-wet state to delay the production decline. Other advantages when using this type of emulsion are cost reduction and improved effectiveness in removing asphaltene deposits, when compared to alternative solvents that have been used. This is of particular significance to those wells where large volumes of a washing phase have to be pumped downhole. Hazards also have been reduced by using relatively high-flash-point aromatics. Continuous mixing of the emulsion when pumping reduces waste and improves the logistics involved in pumping the large volumes needed to treat long openhole sections and/or to treat the fractures deeper in the near-wellbore region.
Two successful field applications in southern Italy will be discussed, describing the placement technique used and the results achieved with this new system. These treatments will be compared to previous treatments using a hydrocarbon-based solvent. In the first well where previous treatments had failed to make significant improvements, following the application of this emulsion the production was almost fully restored and the production decline was significantly slower than previous treatments. The second well treated was a long horizontal wellbore; again, the emulsion and technique proved successful in returning the production to previous levels and sustaining the new level for an extended period of time.
Asphaltene is well known in the industry for causing production loss through plugging the tubing, perforations, and formation. The term "asphaltene" is applied to the black, carbonaceous components of petroleum. These compounds occur in many crude oils in the form of colloidal, suspended, solid particles. They are characterized by their insolubility in light paraffin hydrocarbon solvents, such as pentane or petroleum ether. Chemically, the asphaltene fraction of petroleum is composed of polycyclic, condensed, aromatic rings with several side chains. These compounds have relatively high molecular weights and are considered polar materials because atoms of sulfur, nitrogen, oxygen, and complex metals are present.
Asphaltene precipitation takes place when the crude oil loses its capability to disperse and stabilize the particles. The asphaltene stability depends on the composition of the crude oil, temperature, pressure, and the nature of the reservoir-rock surface. Under static reservoir conditions, asphaltenes normally are held in a stable suspension by resins, a family of polar molecules. Changes in fluid temperature and pressure that are associated with oil production from the reservoir may cause the asphaltene to flocculate and precipitate out of suspension and adsorb to the rock or pipe surfaces. Additionally, the asphaltenes may flocculate because of electrical charges created by the motion of flowing hydrocarbons. Asphaltenes may also flocculate by mixing of different oil types (e.g., along a flowline collecting oil from different wells/reservoirs). To compound the problem further, emulsions can be stabilized by asphaltenes. Regardless of the mechanism causing the asphaltene to deposit, the result is a plugging effect that inhibits or reduces oil production. Precipitation of asphaltene particles may also provide nuclei for paraffins to start precipitating, as in the case of the wells discussed in this paper where the deposits are frequently a combination of asphaltene and paraffin, often associated with inorganic material such as formation solids, salts, and iron oxides.
The variable nature of the asphaltene problems is caused by reservoir conditions and chemistry of the oil. Intervention-treatment design and timing is based generally on local practices that are put in place to manage the problem. In the field described in this paper, there had been long-established practices to determine the timing and the method of the intervention. The same practices, however, were no longer achieving the success of the past, and the severity of the problem was increasing with the age of the field. To improve the performance of the treatments with the changing reservoir conditions, a review of the local practices was implemented. It was during this review that the emulsion system described in this paper was developed. The remainder of the paper describes the methods used to develop and optimize the solvent, leading to the development of the emulsion system. This emulsion system was then applied in the field. Two case histories in two different well configurations (perforated casing and horizontal open hole) in the same field are described to illustrate the application.
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