This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
Summary 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. Background 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.
The paper presents a case history of a successful operation that was performed to reduce excessive water production in a horizontal well drilled through a naturally fractured carbonate reservoir. Because the well was completed with a 940-m horizontal openhole section, there were two significant issues in the attempt to reduce water cut without the use of a workover rig. There was no practical means of selectively isolating sections of the open hole, and even if it could be achieved, the fractures producing water could not be identified and individually isolated. A treatment was performed employing a sealant that would set up only in presence of water and would remain fluid in anhydrous conditions. This sealant was placed using a coiled tubing unit (CTU) and then overdisplaced into the formation, into the natural fracture system. Before the treatment, this naturally flowing prolific oil producer would not flow because of the hydrostatic pressure from the excessive water cut (i.e., >60%). Following the treatment, the well flowed at approximately 20% water cut for a few days, stabilized at 40%, and has remained in natural flow since the treatment. This paper describes the philosophy behind the treatment design, the testing of the sealant, the placement procedure, subsequent well operations, and well performance. To re-establish this well into productive natural flow without the use of a workover rig was considered to be a significant success, and the long-lived effectiveness of the treatment has exceeded expectations. Introduction This case study is taken from a south Italy field that lies within a mountainous national park area and is currently classified as the largest producing onshore field in continental Europe. Wells in the field are also very high producing wells from a naturally fractured carbonate reservoir lying at approximately 3500 m total vertical depth (TVD). Permeability is difficult to predict because it is dependent on natural fracturing, which results in a wide range of production rates from individual wells. Because the field is in a national park, development is strictly controlled and wellsites limited to fit in with the environment; therefore most is made of the existing sites. Wells in the field have highly extended well profiles, and more recently, multi-lateral completions. The flow line system is also complex because it may need to cross several valleys to reach the production station; hence wellhead pressures are necessary to produce through the flow line system. Very strict governmental controls on the operations in the field help ensure that work is minimized to only what is absolutely essential to develop the resources. Planning to move a rig onto the wellsite is normally a long process to obtain the required authorizations, and particularly expensive because of the mountainous terrain. Against this background, rigless interventions and the use of coiled tubing (CT) in the field have become widespread. When a naturally flowing well suddenly starts producing excess water, and oil production is lost because the well is killed by increased hydrostatic pressure, there is an intense commercial driver to attempt to resolve the problem with a rigless intervention. This situation offers an opportunity to use newer techniques because the commercial benefits of a successful job make the amount of risk acceptable to an operator willing to resolve the problem. This scenario provides a rare opportunity to try untried methods and was the case in the job described in this paper. While the technology described here has been used in the industry since the early 1990s, no published cases of similar work were found in similar demanding well conditions, i.e., a horizontal well with no means of mechanical isolation and no identifiable water source. The technique, however, proved to be a commercial success in re-establishing production from the well and proved to be long-lasting.
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 common to the industry as whole. In Italy regular treatments using 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 re-disposition of the asphaltene in the formation and increases the speed 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 successfully used 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 employed. This is of particular significance to these wells where large volumes of a washing phase have to be pumped downhole. Hazards have also 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 south Italy will be discussed in detail, describing the placement technique employed 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 practically 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. Background 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, petroleum ether, etc. 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 molecules of sulphur, 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 are normally 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, for example, along a flowline collecting oil from different wells/reservoirs. To further compound the problem, 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 e.g., 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.
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