Production chemicals are typically complex mixtures of various molecular compounds. Some of these chemicals are soluble in water and dissolve in produced water to make the discharged produced water toxic to the environment. Biocides, demulsifiers, corrosion inhibitors and scale inhibitors pose the greatest concerns for aquatic toxicity, but studies have shown that they may undergo reactions that reduce their toxicity before they are discharged or disposed [17]. Some of the physical and chemical properties of these production chemicals are highlighted in the subsequent sections.

Corrosion inhibitors are mostly water-soluble fluids and could be classified according to its mode of operation as either anodic, cathodic, vapour phase or film forming [18]. The Film Forming Corrosion Inhibitors (FFCI) are useful in the prevention of chloride, carbon dioxide (CO₂) and H₂S corrosion can be deployed in continuous injection or batch treatment. On the basis of this versatility, the FFCI are the mostly inhibitors for the protection of crude oil, condensate and gas production lines. The typical dosage of active FFCI components are often in the range of 10-100 ppm [19]. These corrosion inhibitors are adsorbed to the metal surface forming protective layer thereby preventing corrosive chemicals such as water and chloride ions from penetrating the surface of the metal [20]. Common corrosion inhibitors include acetaldehyde, acetone, ethoxylated octylphenol, nonylphenol, isopropanol, ethyl methyl derivatives, formic acid, isopropanol, thioglycolic acid, diethylenetriamine and naphtene acid imidazolines. In general, corrosion inhibitors are highly soluble, biodegradable and have low log values indicating that the chemicals are not likely to sorb to soils hence there is potential for leaching to groundwater. They are known to contain compounds that are toxic and/or carcinogenic [21].

Scale inhibitors are also water-soluble chemicals whose job is the prevention or retardation of the growth of inorganic scales. The process of scale inhibition is achieved through the adsorption of the chemicals onto the crystal surfaces. Some well-known scale inhibitors include amino-phosphonates, acrylamide, sodium, methanol, polycarboxylate, and ammonium bisulphate. Polyphosphates, phosphate esters, small nonpolymeric phosphonates, amino-phosphonates, poly-phosphonates, polycarboxylates, phosphino polymers, polyphosphinates and polysulphonates are also some common classes of scale inhibitors. The deployment of scale inhibitor in production process is site-specific, it is also dependent on the flow of fluid and the results of produced water analysis. Typically, a scale inhibitor dosage rate of 2-5 milligrams per litre (mg/L) is adequate to prevent scaling [22].

Biocides are used in oil and gas production to kill or eliminate micro-organisms which can cause Microbially Induced Corrosion (MIC) and fouling. They are basically of two types: oxidising and non-oxidising (organic) biocides. Oxidising biocides cause irreversible oxidation/hydrolysis of protein groups in the micro-organism and in the polysaccharides that bind the microorganisms to the surfaces of the equipment [23]. Ozone, hydrogen peroxide, chlorine, chlorine dioxide and bromine are the oxidising agents most commonly used as biocides [24], [25]. Non-oxidising organic biocides are less prone to cause corrosion than oxidising biocides, in fact, some can inhibit corrosion. Examples of non-oxidising biocides are aldehydes, bronopol, DPNPA, and acrolein [26].

Paraffin inhibitors are chemicals that have the capacity to affect the Wax Appearance Temperature (WAT) in the reservoir fluid during crude oil production [27]. These chemicals which are also referred to as wax crystal modifiers prevent the deposition of wax during crude oil production by modifying the structure of the wax crystals. Pour Point Depressants (PPDs) or flow improvers are another class of chemicals that alter the pour point of wax. There is a good deal of overlap in the chemistry and mechanisms of the two classes of chemicals, most wax inhibitors also function as PPDs. It is best practice to deploy wax inhibitors and PPDs into pipelines before the bulk temperature drops below the WAT [28]. The concentration of wax inhibitor or PPD needed depends on the severity of the wax problem, but 100-2,000 ppm covers most application needs. The main classes of wax inhibitors and PPDs are ethylene polymers and copolymers, comb polymers and miscellaneous branched polymers with long alkyl groups [20]. A mix of a weak to moderate wax solvent, such as toluene or xylene, and a strong wax solvent, such as cyclopentane or cyclohexane, can be deployed as wax inhibitor in cold climates. Ethylene/vinyl Acetate (EVA) copolymers in various solvents and cyclohexane are also good wax inhibitors and can be used to improve flow in pipelines [29].

The process of separating free water and the dissolved salts in the oil-water emulsion from the crude oil is called demulsification. Although the application of heat to emulsion has been shown to help in demulsification, carboxylate and naphtenate emulsions are not affected by heat thus the addition of a demulsifier remains the best way to resolve an emulsion. The concentration of the added demulsifier is usually in the range of 5-500 ppm based on the water phase. Enough mixing/dispersing is required to get the demulsifier to the oil-water interface, and time must be allowed for the coalesced droplets to phase separate. Some examples of demulsifiers include those containing an anionic surfactant (e.g., an alkylsulphosuccinate or alkylphosphonic acid, and their salts), a non-ionic surfactant (e.g., ethylene oxide/propylene oxide copolymer, ethoxylated fatty acid of polyethylene glycol, terpene alkoxylate, or modified alkanolamide), and a solvent base comprising blends of dibasic esters [20].

In crude oil production, when wax deposition cannot be prevented or when the prevention technique employed fail to deliver the required result, removal of the deposits becomes necessary in order to avoid production downtime or decreased production. Wax removing in pipeline is a common issue and many methods to achieve this have been developed. Trials of these methods in well tubing have recorded success in a few and these include mechanical removal methods, fused chemical exothermic reactions and wax-removing chemicals (paraffin solvents and dispersants) [29]. Two types of chemicals are commonly used for removing wax depositions, the first generates heat as a result of an exothermal chemical reaction, which occurs in the well when it is mixed with other specific chemicals or water, the second group of chemicals includes the solvents and dispersants that need to be added continuously to treat the oil [29]. A combination of sodium nitrite and ammonium chloride relying on the exothermal effects and the effervescence has been tried for wax deposit removal with reported success [30], [31]:

${\mathrm{NaNO}}_2+{\mathrm{NH}}_4\mathrm{Cl}\to \mathrm{NaCl}+{\mathrm{N}}_2+2{\mathrm{H}}_2\mathrm{O}$ (1)

Gasoline, kerosene or benzol are the oldest wax solvents known. Although diesel condensate and toluene have also been used, xylene, carbon disulphide and carbon tetra chloride have been shown to do better [29]. Studies have shown that the temperature difference between the fluid within the pipeline and the wall of pipeline is the most important factor for wax deposition and that the amount of wax deposited decreases with increased flow [32].

The IFS, which is currently operated by Addax Petroleum Development Nigeria Limited, is an onshore crude oil and natural gas facility located Oil Mining Lease (OML) 124 in Izombe, Oguta Local Government Area of Imo State, Nigeria. The flow station, which was commissioned on 6 June 1975, is a complete self-sufficient facility containing oil and gas production and processing systems: oil production process, gas compression and re-injection systems and produced water re-injection unit as contained in Figure 2. IFS was originally designed to receive 37,000 barrels per day of well fluids from Izombe, Ossu, Njaba and Jisike fields. However, the current crude oil production of the facility is 3,300 barrels per day and the crude oil-produced water ratio is 0.3.

Figure 2

Simplified produced water process flow diagram for IFS

Considering the age of the fields, several production chemicals are employed for crude oil production in IFS. These chemicals are injected at different points along the production process at different times employing different methods. Table 1 provides detailed information on production chemicals use at IFS. The wax remover is not injected continuously but as scheduled fortnightly during the routine pigging operations through the Main Oil Line (MOL) that delivers stabilised crude oil to the export terminal. The wax remover is not involved in crude oil production and therefore not considered to play a role in this research.

The samples of produced water for this research work have been analysed at Taochem Limited’s laboratory in Port Harcourt, Rivers State, Nigeria. This laboratory is accredited by the Department of Petroleum Resources to provide consultancy services in production chemistry and auditing of laboratory services for Nigeria’s oil and gas industry. The results of the laboratory analysis have been relied upon for the predictions and conclusions in this research.

The influence of injection of production chemicals at the various sampling points on the quality of the produced water have been studied by laboratory analysis of the various samples of produced water captured at both upstream and downstream of the injection points along the production process as shown in Table 2. The results of the laboratory results have been analysed and presented for easy evaluation in Table 3.

The production process is made up of equipment designed to operate at different temperatures. In order to fully assess the impact of the operating temperatures of these equipment on the produced water content that flow through them, samples of produced water have been subjected to different temperatures for 2 minutes each in an oven in the laboratory. The results of this exercise are recorded in Table 4.

As produced water is transported from the Wellhead to the Water Gun Barrel from which it is injected back to the reservoir, time elapsed. In order to evaluate the minimum influence of residence time on the pollutant concentrations in produced water, laboratory analysis have been conducted on produced water samples. The results of the laboratory test are recorded in Table 5.

The concentrations of benzene, toluene, phenol, chromium, iron, zinc, phosphates, ammonia, nitrates and salinity in the produced water have been considered in the analysis of the results from the laboratory. Figure 3 and Figure 4 show that except for nitrates the concentrations of pollutants in produced water increased between Sampling Point 1 (SP1) and SP4 as production chemicals are injected into the process. There is, however, a continuous decrease in the concentration of all pollutants except phosphates between SP4 and SP6 not minding that biocides and corrosion inhibitors are injected upstream SP5 and SP6, respectively.

Figure 5 and Figure 6 also show that while benzene, toluene and phenol concentrations decreased when produced water samples are subject to heat, the concentrations of chromium, phosphates, nitrates and ammonia increased in the samples. The salinity of the samples marginally increased while the concentrations of iron ions remained relatively stable.

Figure 7 indicates that if time is allowed to elapse, the concentration of benzene, toluene and phenol in a produced water sample will decrease while the concentration of chromium, zinc, phosphate and nitrates will increase.

Figure 3

Pollutant volumetric concentration differences between sampling points due to injection of production chemicals

Figure 4

Bar chart illustration of pollutant volumetric concentration differences between sampling points

Figure 5

Average influence of heat on the volumetric concentration of pollutants in produced water across the production facility

Figure 6

Bar chart illustration of the average influence of heat on the volumetric concentration of pollutants in produced water across the production facility

Figure 7

Bar chart illustration of the influence of residence time on the volumetric concentration of pollutants across the production facility

It was observed that at the introduction of a particular production chemical, the concentration of some pollutants increased significantly. This may have been due to the presence of the pollutant as a constituent in the make up of the chemical or due to reaction with other compounds. The percentage increase of volumetric concentrations of the particular pollutant could then be calculated at that point using the ratio of the change in volumetric concentration to the original concentration of the pollutant prior to addition of the chemical. In the case study, the introduction of scale inhibitor, paraffin inhibitor, demulsifier, biocides and corrosion inhibitor at the recommended rate for the process yielded an increase of 242%, 53%, 12.5%, 300% and −4.8% in the volumetric concentrations of ammonia, hydrocarbons, salinity, phosphates and nitrates in the produced water.