Water injection is an enhanced oil recovery method which is applied for number of reservoirs around the world especially offshore fields. Sea-water injection process is usually associated with important concerns affecting the efficiency, safety, and economy of the operation like formation damage, mineral scaling, early breakthrough and corrosion. Incompatibility between injected and formation waters may result in inorganic scale precipitation in the reservoir and then reduction of oil production rate (productivity loss) and water injection rate (injectivity loss). A comprehensive study supported by reliable modeling and experimental investigation will therefore, significantly improve the success of the operation.

In this paper, mineral scale deposition phenomenon in one of Iranian offshore carbonate oil reservoir under water injection is studied and its influence on reservoir performance and production rate is investigated. For this purpose, an extensive experimental work has been conducted on compatibility of sea and formation waters and the amount and type of scale formed as a result of mixing different portions of these waters. Experimental results have been applied and incorporated with simulation studies. STARS simulator (from CMG 2005) that is capable of evaluating the effect of scale formation on reservoir performance allowing for alteration of permeability and the flow path has been used in simulation study. One of the major contributions of this work is to incorporate the equilibrium conditions, reaction rates and solubility parameters for various scale types in reservoir simulation, so the results can be more realistic. The simulation results show that in oil reservoirs under water injection, scale formation undermines the productivity index and has a major impact on reservoir performance. These results have been confirmed by production history of the field.


Water injection is a common IOR method, usually applied in offshore oil fields for the purpose of pressure maintenance and enhanced oil recovery. During secondary and tertiary recovery by this method, reductions of permeability have been observed in many reservoirs. Several sources are recognized as possibly contributing to this problem such as mineral scale deposition, solid invasion, clay swelling and rock-fluid incompatibility. One of the most important and hazardous of these phenomena is mineral scale deposition due to the incompatibility between injected and formation waters and changes in temperature, pressure, gas dissolution and pH. In the other hand, this is a process of deposition of scales from aqueous solutions of minerals, referred to as brines, when they become supersaturated as a result of the alteration of the state of their thermodynamic and chemical equilibria 1.

In water injection process, mineral scale deposition generally occurs when foreign fluids (usually brines) are contacted with one another. Fluids rich in divalent ions such as Calcium, Magnesium, Barium and Strontium often tend to be the worst offenders in this area, even though their high divalent ion concentration may make them desirable for inhibiting formation damage from a clay swelling or deflocculation viewpoint. Mineral scale deposition causes serious damage in utilization systems and reduces flow areas. Well production and injection rates and capacities thus drop, with consequent economical loss. For example, BP loses around 4 million bbls per year in the North Sea.2 It can also plug production lines and equipment and impair fluid flow. The consequence could be production-equipment failure, emergency shutdown, increased maintenance cost, and overall decrease in production efficiency. The failure of these equipments could result in safety hazards.3, 4, 5

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