A Case Study of Seawater Injection Incompatibility
- John Chapin Lindlof (Arabian American Oil Co.) | Kenneth G. Stoffer (Arabian American Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1983
- Document Type
- Journal Paper
- 1,256 - 1,262
- 1983. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 6.5.2 Water use, produced water discharge and disposal, 4.2.3 Materials and Corrosion, 5.5 Reservoir Simulation, 5.4.1 Waterflooding, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 3.4.4 Downhole Chemical Treatments and Fluid Compatibility, 4.3.4 Scale
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One of the primary concerns in the implementation of an effective waterflood is the compatibility between the formation water and the water to be injected. The Arabian American Oil Co. (ARAMCO) and the Saudi Arabian Ministry of Petroleum and Mineral Resources Technical Branch recognized a potential incompatibility problem and embarked on a comprehensive program to evaluate possible strontium sulfate and calcium sulfate scaling associated with the injection of seawater into the Arab-D reservoir in the northern areas of Ghawar field.
Waterflooding of the northern areas of the Ghawar field, the world's largest known oil field, with the Wasia aquifer as the source water began in 1965. As the reservoir pressure-maintenance program continued, a decision was made to replace Wasia water injection in the north 'Uthmaniyah area of the field with seawater injection. To meet this requirement, a 4.2-million B/D (0.67 x 10(6) -m3) seawater-treatment plant, with associated distribution and injection facilities, was placed in operation in June 1978.
The initial Wasia waterflood and the subsequent seawaterflood in the north 'Uthmaniyah area, together with the connate Arab-D formation water, represented a three-water system with a possible incompatibility problem. Basic to the understanding of water incompatibility in this instance was knowledge of the solubilities of the sulfates of barium, calcium, and strontium, and how their solubilities are affected by changes in salinity, temperature,, and pressure. Particular emphasis was placed on laboratory work to determine the solubility of strontium sulfate, since strontium sulfate solubility data in the literature were limited. This work supplemented the available strontium sulfate solubility data. Results of this testing have been reported in Ref. 8.
Additional phases of the evaluation program, which are the subject of this paper, included extensive laboratory analyses and water s stem evaluations, reservoir simulation studies, field tests, and other procedures.
The solubility of calcium sulfate is an order of magnitude greater than that of strontium sulfate, which in turn is about one and one-half orders of magnitude greater than that of barium sulfate (Fig. 1). Such data, however, can be misleading. Fig. 1 indicates, for example, that the solubility of strontium sulfate can be greater than 950 mg/L (mg/dm3 ). This solubility, however, is true only when the solution is stoichiometrically balanced-i.e., when the number of strontium ions equals the number of sulfate ions. If an excess of either ion is introduced, the solubility is depressed markedly. This is known as the "common ion effect."
As the solubility of strontium sulfate is decreased by the common ion effect, the supersaturation becomes a disproportionately higher percentage of total strontium sulfate in the solution. The Supersaturation represents the amount of strontium sulfate present in excess of the solubility and thus represents the amount available for precipitation from solution and possible scaling. The supersaturation exists in a metastable state and, as such, the manner in which it exists in solution or comes out of solution by crystallization and precipitation is entirely unpredictable.
Fig. 2 illustrates the common ion effect for mixtures of Arab-D formation water and seawater.
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