As the produced water market continues to grow, the focus on produced water issues has increased not only because of the rising volumes of water generated by oil and gas operations but because the industry is increasingly risk-averse and environmentally aware.
Produced water typically contains a combination of hydrocarbons and other constituents. These include salts, chemical additives and toxic compounds as well as solid wastes with harmful substances such as boron, sulfates, radioactive elements and heavy metals.
The water already present in the reservoir and the use of water injection techniques to aid the secondary recovery process generates the largest volume byproduct stream with some 21 Bbbl of produced water generated each year in the U.S. alone. With 1 bbl equating to 159 l (42 gal), this figure represents about 57 MMbbl/d or 9 billion l/d (2.4 billion gal/d), according to the U.S. National Energy Technology Laboratory (NETL).
Growing volumes of produced water have meant E&P firms have effectively become water management firms. They are spending an increasing amount of time, effort and resources treating water for reuse, reinjection or environmentally acceptable discharge.
NETL puts the water-to-oil ratio—the volume of water produced for every barrel of oil recovered—between 5:1 and 8:1 in the U.S. Analysts at BCC Research believe that the water-to-oil ratio in North America will increase to 12:1 by 2025 and 50:1 in the worst cases. With producers paying anywhere between $3/bbl and $12/bbl to dispose of produced water, the research firm expects the North American market for produced water treatment equipment to reach $1.2 billion by 2017.
The properties of produced water vary depending on geographic location, geologic formation and the type of hydrocarbon produced. It also may include water from the reservoir, injection water and any chemicals added during production.
Produced water is unique to every asset, meaning the treatment and filtration requirements are myriad and diverse. The composition of the produced water dictates the treatment technologies necessary to meet mandated limits.
Produced water can be treated through gravity separation, flotation and filtration to physically or mechanically remove contaminants. The applications of various proprietary technologies depend on the nature and volumes of the produced fluids.
The first stage of the separation process relies on the effects of gravity and density difference while the fluids remain within the separator. A long residence time relative to the differential specific gravity of the phases is essential. The simplest solution is to employ a large tank for storing the produced water where time facilitates the separation.
Offshore, the requirement for a long residence time must be balanced against the footprint limitations placed on the separation tank. Several technologies are employed to eliminate oil droplets at the primary separation stage, including hydrocyclones and plate coalescers. This is followed by flotation and filtration, with adsorbents and absorbents typically used after the filtration stage. Offshore technology evolution has been driven by regulation and project economics. Reducing the weight of produced water solutions while ensuring high reliability translates to a smaller footprint.
Having met local mandates, some producers in Norway are now looking to exploit technology advancements to recover more crude. The CTour process is one of the only technologies in the world that can cost-effectively remove both dispersed and dissolved hydrocarbons from large volumes of produced water while effectively increasing the crude that can be recovered.
Whereas the best available technology for de-oiling produced water is a hydrocyclone/degasser-float cell configuration that yields an average discharge concentration of less than 25 ppm, the CTour process can yield a residual discharge as low as 2 ppm to 3 ppm total petroleum hydrocarbons while removing 90% to 95% of hazardous dissolved hydrocarbons. The CTour process can treat large volumes of produced water at low footprint, capex and opex while reducing chemical use. This represents a shift in produced water management, and future legislation based on this technology is anticipated.
Certainly, there are several produced water technologies available today offering drastic improvements on the technology employed on some platforms. However, with cost and compliance being primary decision factors, the adoption of innovative technologies is often gradual.
Yet technology choices made at the project outset influence long-term opex and thus an asset’s overall profitability. For newbuilds, where produced water volumes will not be significant in the first few years of operation, the experience of a produced water specialist can come to the fore in terms of reducing the potential cost of a retrofit later vs. installation from the start.
Likewise, if the operator intends to decommission or divest an asset in the short-to-medium term, it may be unwilling to invest in a more expensive solution. Selecting a lower cost solution can prove a false economy. Issues can be encountered as produced water volumes rise or if the chemistry of the reservoir changes over time.
Analysts at IHS have warned that water management risks have increased rapidly due to regulatory compliance requirements, costs, concerns over water scarcity and quality, and the industry’s need to preserve its social license to produce the hydrocarbons. Without an effective water management strategy in place, operators risk lower production rates, damaged wells, or compromised drilling and completion operations programs. Regulatory penalties also apply if damage to the environment occurs, compromising stakeholder faith.
Produced water requirements must be addressed on a case-by-case basis. It is not possible for E&P companies to specify an optimum solution across their entire fleet. Ideally, the operator should conduct a pilot study to ensure the proposed solution delivers the required results.
Ultimately, the tactical goal is to build an optimum solution for the application in question, but the strategic aim is to develop a process solutions roadmap meeting the operator’s long-term goals. Operators in particular would benefit from a single solution supplier. Smaller providers tend to be more nimble and responsive in building a competitive solution based on the best available technologies.
Previously, operators would dedicate minimum time and resources to the treatment, handling and disposal of produced water, but in today’s risk-averse and environmentally aware atmosphere, produced water contains contaminants that require time, money and resources to handle effectively.
Although carbon capture, transport, use and storage is dominated by oil and gas producers now, it represents a significant growth area for the midstream sector.
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The company forecasted its 2022 EBITDA between C$15 billion and C$15.6 billion, higher than its 2021 expectations of C$13.9 billion to C$14.3 billion.