Water Treatment in Oil & Gas Business
Reservoirs, according to many outside the oil and gas industry, are huge subterranean hydrocarbon lakes. In reality, hydrocarbons are found in porous layers of rock that are covered by impermeable rock or shale. Sandstone and limestone are the most common oil-bearing rocks. The pores in these rocks range in size from sub-micron to tens of microns. This enables fluids to pass through the rocks.
The water beneath the oil is also known as “connate” or “formation” water. Their origins differ. Connate water is water that was caught in rock during formation and whose composition can change over time. Under the impermeable cap rock, formation water is trapped with the hydrocarbons. When an oil well is dug, it produces oil, gas, and water all at the same time
When reservoir fluids (gas, oil, and water) are brought to the surface for separation and treatment, the pressure drops, resulting in the formation of insoluble scales. In basic language, decreased pressure causes soluble bicarbonates to form carbonate ions,
- releasing CO2 gas: 2HCO3− → CO32− + CO2↑ + H2O
When coupled with calcium ions, the carbonate ion produces insoluble carbonate scales. This can result in reduced flowrates (loss of money) as well as a loss of system integrity. To avoid scale formation, reservoir fluids can be dosed with a scale inhibitor chemical while still under high pressure. The first stage of oil separation is typically a horizontal three-phase separator sized to optimize oil and water residence times. It is critical to handle the removal and disposal of solids generated by the use of oil, gas, and water. All gas/oil/water/solid separation in these units is governed by Stokes’ Law.
It is, in truth, far from clean. It will contain particles as well as residual oil in the form of small droplets distributed in water. Water will include certain dissolved hydrocarbons and gases, such as (corrosive) carbon dioxide and lighter hydrocarbons, as well as water-soluble chemicals required to enhance hydrocarbon production. Water from onshore and offshore oil and gas production systems is discharged into local river courses, estuaries or near-coastal waterways, or the sea from offshore oil and gas production platforms. The presence of potential toxins in these streams must be addressed in order to protect the ecology. A little number of hydrocarbons in the water may be recovered and reintroduced into the main production system
Mineral therapy was used in the early stages of treatment, which eliminated larger oil droplets but not small ones. For removing dispersed oil droplets from produced water, the following methods have been developed:
- increasing the overall droplet size (coalescence)
- systems which change the specific gravity of the oil droplet by attaching to it a bubble of gas
- techniques that apply increased gravitational forces to the separation process, for example, hydro cyclones and centrifuges
These advances in reducing residual hydrocarbons in produced waters enable dispersed oil in water (OIW) concentrations as low as 40 mg/l. Initially, this was sufficient to meet the discharge standards of the UK regulatory agency. A new regulation mandates offshore businesses to reduce the number of hydrocarbons leaked overboard on an annual basis.
This amount of oil should be 15% less than the total tonnage delivered by the individual assets in 2001. Any quantity of hydrocarbon released in excess of the permitted level is subject to a fine of £108 per kilogram. These calculations do not take into account new fields or the fact that water production grows with time.
Currently, the maximum OIW value in produced waters is 30mg/l. As a result, some operators must treat generated water to significantly higher standards than previously, while others have set a zero produced water discharge goal for both existing and new assets. The competent environmental protection agency regulates onshore discharges, which may include maximum limitations for heavy metals and dissolved hydrocarbons
Two more processes occur while the oil is produced. As the gas cap expands, so does the oil/water contact. The first mechanism is unfavorable because it permits dissolved gas in oil to leave solution. Gas is more mobile than oil and will gravitate toward producing wells.
This is undesirable since it means that oil is bypassed and remains in the reservoir. When the oil/water contact is increased, more water is created along with the oil. This decreases oil income while increasing the amount of water that must be treated before it can be discharged.
How can these approaches be avoided, or at the very least delayed, until the field’s revenue is maximized? The advantages of allowing water to flow into oilfields were discovered by chance as early as the early American oilfields. Water used to infiltrate oil-bearing strata by mistake and flush the oil towards the producing wells. Since then, knowledge has expanded significantly, and water injection is now employed in nearly all new oilfields.
The injected water has two purposes: it maintains reservoir pressure high enough so that gas cannot leave solution, and it creates an immiscible flood front that drives oil towards the wells. Regardless of the approach used, the total volume of oil recovered will increase dramatically. According to World Oil, a successful water injection operation may increase overall hydrocarbon recovery by 40%.
- Seawater (if the asset is offshore or near the coast with a few exceptions)
- Produced Waters (see above)
- Aquifer waters (if easily accessible)
- River or estuarine waters
- Domestic and/or industrial waste waters
The Saudi Aramco Qurayyah system purifies 7 million barrels of seawater per day (1.1 million m3/day) before pumping it 350-400 kilometers inland for injection into the Ghawar oilfield. Since 1978, the plant’s capacity has been increased, and it now serves the Khurais oilfield. Before they can be safely injected into a hydrocarbon-bearing deposit, all of them must be treated
Injection Water Use
The current issue of injection water treatment will concentrate on saltwater, which is the most commonly used injection water. Seawater contains suspended particles, bacteria, and dissolved oxygen, all of which may wreak havoc on the reservoir’s ability to store water for extended periods of time, as well as the materials used to manage the water. Pipelines, injection wells, and any metals used beneath the ground to transport water to the reservoir are examples. Because saltwater may be used for cooling, it must first meet the cooling quality standards. This includes the removal of pathogens, marine life, and the treatment of larger suspended particles.
This is accomplished by injecting broad-spectrum bactericides, mostly chlorine in the form of sodium hypochlorite, into the water supply pumps. This is typically produced via seawater electrolysis. The larger suspended particles, such as hard–shelled marine animals and plankton, are next removed via coarse filtration. These filters remove a variety of particles depending on how the water is used. The typical range for solid removal is 80m to 6.4mm. After cooling, water injected into a hydrocarbon-bearing deposit may require further filtration.
There are now two schools of thought on this topic: one advocate’s filtration to avoid reservoir pore obstruction, while the other claims that cold seawater entering hot rock will produce rock fissures, allowing water (and particles) to flow freely. A bank of high-rate dual media downflow filters is often used for secondary filtering. After eliminating the sediments and most bacteria, the dissolved oxygen must be treated.
Because carbon steel is preferred for handling the high pressures required to inject water into the formation, the dissolved oxygen must be removed. This oxygen is removed from the seawater using vacuum deaeration, which entails a vertical tank with many vacuum stages.
- The remaining dissolved oxygen is removed using a scavenger chemical based on sulphite : SO32− + O2 → SO42−
The first stage vacuum is typically provided by liquid ring vacuum pumps, with lower vacuums provided by air/gas ejectors. In most cases, the pump seal/cooling water is cold filtered seawater. The conditioned saltwater is then pushed under high pressure to the water injection wells. The switch from aerobic to anaerobic conditions downstream of the deaerator can allow some anaerobic microorganisms to grow, notably sulphate reduction bacteria, potentially jeopardizing the integrity of any carbon steel systems Microbiologically influenced corrosion is often mitigated by intermittent use of organic, non-oxidizing biocides (MIC). No corrosive properties like chlorine. Aldehydes, quaternary ammonium compounds, and various kinds of quaternary phosphonium compounds are dosed alone or in combination as single or mixed chemical biocides. Organic biocides are expensive and are typically dosed once a week for 1-2 hours at 1,000 mg/l.
This is based on measurements of water quality downstream of the biocide dosing site for both planktonic and sessile bacterial species. Finally, if the saltwater and formation water with which it interacts are chemically incompatible, water injected into a hydrocarbon-containing reservoir may generate intractable scales. Depending on the severity of the problem, adding a scale-inhibiting chemical to the injection water may suffice.
Insoluble barium and strontium sulphates can occur if the formation water has high levels of higher alkaline earths (especially barium and strontium) and the injection water contains 2,700 mg/l sulphate ions. The number of scales created is frequently too enormous for a chemical scale inhibitor to be effective. Saltwater is commonly routed through a bank of nano-filters, which efficiently remove divalent ions such as sulphate. This allows for the safe injection of treated water into high barium/strontium reservoirs without impacting injectivity or production.
Clearly, treating injection water is a major undertaking. The most important aspect of any system is including the operations team in the design stage. The operations team will be responsible for ensuring that the system functions as expected
- The Benefits of Water Treatment
The oil and gas industry are heavily reliant on freshwater. Some businesses even use water to generate electricity. Water is required for cooking, drinking, and bathing. However, fresh water is frequently scarce where operators use it the most.
- Excessive Water Production
More oil and gas companies are digging in the Arctic to access rich resources that were previously hidden behind thick layers of permafrost. However, any freshwater found under these extreme conditions is frozen. Workers in the Arctic want consistent water supplies, but the severe climate requires a water filtration system that can withstand sub-zero temperatures and earthquakes