A Feasibility Study of Mixing Disposal Water with Aquifer Water for Downhole Injection

Abstract

Abstract Disposal of wastewater produced from various gas oil separation plants is a major concern for many oil companies. Mixing of wastewater with injection water has many economical and environmental advantages. The objective of the present study is to determine the feasibility of mixing produced water with the injection water obtained from a shallow aquifer. Several samples were collected from disposal water and injection water locations. Measurements of hydrogen sulfide and total iron were conducted on site using standard techniques. The concentration of H2S in disposal water was found to be in the range of 550 - 765 mg/L. The aquifer water contains 4 - 5 mg/L of total iron. Compatibility tests conducted in the lab and on-site showed the formation of iron sulfide. Acid solubility tests and XRD analysis confirms that this iron sulfide is present in a non-crystalline, acid-soluble form (amorphous). The presence of iron sulfide in disposal waters is a major concern because it can cause formation damage and subsequent loss of well injectivity. Various chemicals were evaluated to mitigate the formation of iron sulfide. These chemicals ranged from formaldehyde, triazine, to tetrakis hydroxymethyl phosphonium sulfate, to oxidizers (sodium hypochlorite, hydrogen peroxide and sodium nitrite). Similarly, some iron chelating agents, such as citric acid, ethylenediamine tetraacetic acid, and nitrilotriacetic acid were evaluated. This paper will discuss various types of H2S scavengers, reactions with H2S, advantages and disadvantages of each chemical based on extensive lab and field studies. Chelating agents for dissolved iron were also evaluated. Higher dosages of either sodium hypochlorite (hydrogen sulfide scavenger) or citric acid (iron sequestering agent) can mitigate the precipitation of iron sulfide species up to 15 vol% of disposal water in the mixture. Introduction A major portion of Field "B" is located off-shore along the western edge of the Arabian Gulf. It produces crude oil (°API = 38) and is sour (contains up to 7.5 mol% H2S). Oil production is obtained from two main carbonate reservoirs. The majority of the wet producing wells have been experiencing calcium carbonate scale, starting from the top 500 ft of the tubing. The produced water has high calcium and bicarbonate contents (Table 1). It precipitates calcium carbonate scale once the pressure falls below the bubble point, and CO2 separates out of solution.. The CaCO3 deposition reaction is represented by the Equation 1.Equation 1 Scale mitigation strategy adopted in this field (both encapsulated and squeeze treatments) has been successful. In addition, a polymer based scale inhibitor treatment is in place at the gas oil separation plant (GOSP) to minimize the downstream scale problems. Peripheral water injection is used to maintain reservoir pressure. The injection water is obtained from a shallow sandstone aquifer and is produced from 21 supply wells, which are equipped with electric submersible pumps (ESPs). The aquifer water has low total dissolved solids and is treated in the gas oil separation plant with an amine-based corrosion inhibitor, an oxygen scavenger, and a biocide (batch treatment of one hour per week) before the injection. The produced water is injected into a separate, segregated disposal system. Two booster pumps operating at a maximum capacity of 160 Mbbl/d are used to inject the disposal water into eight on-shore disposal wells. Additional pumps will be required to handle the expected increase in the disposal water over the next few years (nearly 10–20 Mbbl/d). The disposal water contains dissolved H2S, whereas the aquifer water contains dissolved iron (Table 2). When these two waters are mixed together, H2S reacts with the iron ions and precipitates iron sulfide species, as shown in Equation 2.Equation 2 To avoid FeS precipitation, hydrogen sulfide, dissolved iron, or both species should be removed prior to mixing the two waters.