Asphaltene deposits have been observed in a number of high gas-oil ratio (GOR) wells in north Ghawar. Even though the oil reservoir is undersaturated two small gas-caps are present as a result of gas injection during the 1960s and 1970s. New development wells drilled recently to produce oil and gas from the gas-cap areas have experienced asphaltene deposition. The cause of precipitation is the stripping of the asphaltenes from the crude by the gas. This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special PVT apparatus. The effect of gas-oil ratio on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. However, the amount of asphaltene precipitated at the onset is negligible. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Guidelines are provided to alleviate the problem by controlling the GORs. Recipes for solvent treatment including asphaltene dispersants are also described in the paper. Introduction Ghawar field is one of the major oil fields in Saudi Arabia. In the northern part of the field some wells have experienced solid built-up in the wellbore. Analyses of solid samples from several wells have shown the presence of asphaltenes that may have precipitated during crude production and have started to deposit on the wellbore. The solid deposition has been observed in high gas-oil ratio wells. A location map of the wells is shown in Figure 1 and photographs of the solid deposit from one well are shown in Figure 2. The Arab-D reservoir of Ghawar field contains an undersaturated light oil. The bubble point pressure is ~1,900 psi at the reservoir temperature of 215°F and the average gas oil ratio is ~570 scf/stb. The reservoir pressure at present is over 3000 psi. In the 1960s and 1970s the associated gases from part of the field were injected back into the reservoir at two locations due to unavailability of gas processing facilities and to avoid excessive flaring. The injected gases have formed two separate gas caps in the field (north and south gas-caps, Figure 1). In recent years oil production has started from these gas-cap regions. Due to the presence of the gas cap, some of the free gas flows into the oil production wells increasing their total gas oil ratios (GORs). The coning or cresting of gas into the oil has caused limited plugging in a few wells in the north and south gas-cap areas. The gas strips the oil of asphaltenes which precipitate and deposit in the wellbores. Plugging of the wellbore by asphaltenes or organic deposits has the potential to reduce productivity and cause production impairment. Furthermore, several more gas-cap wells are being planned to be drilled in the area and their productivity may be impacted by the deposition tendency. Figure 3 shows the GOR for 11 wells in which asphaltene deposits have been observed. The solid line shows the average GOR for the entire field (~570 scf/stb). Except for one well, the GOR for all wells is higher (in some cases substantially higher) than the average field GOR. The high GOR is a consequence of gas coning/cresting in the wells. The free gas strips the asphaltenes from the crude which deposit in the wellbore. One well was tagged over a period of time to ascertain the buildup of asphaltenes in the well. Figure 4 shows the tag depths and indicates a loss of wellbore accessibility of ~200 ft over a period of 18 months. Recent results show that the buildup has stabilized and the asphaltenes may be dragged with the oil to the gas oil separating plant (GOSP). Other wells are also being monitored and have shown some buildup activity.

Well-control fluids were used during a routine overbalanced workover operation in an offshore well completed in high permeability sandstone. As expected, a fluid loss control pill was used to control the excessive losses encountered during this operation. However, due to the high permeability of the reservoir and the absence of sized particles in the pumped pill; large amount of fluids were lost to the formation before losses were controlled. The deep invasion of fluids laden with high concentration of polymer had inevitably resulted in severe formation damage and impaired production. Several attempts to clean out the wellbore and revive the well flow were unsuccessful with no injectivity either. The well was consequently suspended while a multidisciplinary team was formed to identify the cause of the impairment and recommend a treatment plan.A comprehensive review of detailed field operation and data related to the fluid losses accompanied with laboratory work to identify the damaging mechanism and formulate an optimized remedial treatment was conducted. The lab work included jar testing to assess compatibility and emulsion tendency when different wellbore fluids are mixed with each other and with formation fluids. Analysis of the samples collected from the wellbore was carried out and different treatment fluid options were evaluated using actual field samples. Core flood experiments were also conducted to assess the impact of high-viscosity pills on permeability and ability of remedial treatment in restoring the original permeability.Experimental results revealed partial removal of the polymer invading the core using organic acid. The designed pre-flush composed of mutual solvent with surfactant package was effective in breaking the emulsion from field samples and laboratory-prepared emulsions. A significant improvement in production from this well was realized by application of a cost effective formic acid-based chemical treatment. Proper treatment design with effective displacement technique were also attributed to the successful damage removal and regained well productivity.

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