Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was detected downhole, plugging gravel packing screens and the intake of sub mersible pumps. Scale build-up caused a significant decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom hole temperature of 160ºF.
An emulsified-type scale inhibitor (phosphonate-type) treatment was designed to mitigate scale in this field. The treatment was successfully applied in thirty wells. Some of these wells were de-scaled before the treatment, while other wells were treated before scale detection.
The objectives of the present paper are to assess the outcome of this treatment based on field data and examine the impact of the acid descaling treatments that are us ually conducted prior to the scale squeeze treatments. Samples of produced water from these wells were collected and analyzed over the last few years.
The emulsified scale squeeze treatment was successfully conducted in thirty wells with water cut that ranged from 3-80 vol%. Extensive analysis of samples collected following the treatment highlighted the need to completely lift the spent acid from the formation following acid descaling treatments. Field data indicated that the presence of dissolved iron may adversely affect the performance of the scale inhibitor. Finally, the concentrations of key elements (calcium, iron and phosphorus) in the flow back samples were affected by water cut and whether the well was descaled prior to the squeeze treatment.
Field H is located 100 miles southeast of Riyadh, Saudi Arabia. Oil produc tion from this field began in 1994. Water injection began in late 1994 and early 1995 to maintain reservoir pressure. Until 1997, there were no major problems faced during oil production. After that, a continuous decline in oil production was noted in some wet producers. This decline was mainly attributed to the formation of calcium carbonate scale, which was found to cover the gravel pack screens, and electric submersible pumps.1
Field H is a sandstone reservoir that produces Arabian Super light crude oil (°API > 50). The oil has a very low gas-oil ratio (GOR) and no appreciable CO2 and H2S content. Therefore, electric submersible pumps (ESPs) are used to produce this reservoir. The average reservoir temperature is 160ºF and its thickness ranges from 150 to 200 ft. The sandstone reservoir is weakly consolidated and sanding problems were noted in several wells. To mitigate sand production, the producing wells were gravel packed. To control production of the gravel, the base pipe is wrapped with a 316-stainless steel screen with 0.012 inch opening. The base pipe has 3.5 inch inside diameter and is made of low-carbon steel (L-80). Each well has two to six sets of perforations with a total length of 40 to 160 ft.
Scale formation frequently occurs in the near-wellbore area. Therefore, a scale inhibitor must be present in the formation to prevent or to delay the formation of scale. A scale inhibitor is squeezed into the formation where it is precipitated and/or adsorbed on the reservoir rock with multivalent cations such as calcium. When a treated well is brought back production the inhibitor is dissolved or desorbed from the rock matrix into the produced brine. The inhibitor prevents scale deposition not only in the formation, but also in the tubing string and, possibly, the surface equipment.
Numerous chemicals are available to prevent scale formation, but the most effective scale inhibitor used in Field H to prevent scale in wet oil producers is organophosphonate, diethylenetriaminepenta (methyl
