Technology, Innovation and Collaboration Drive Produced Water Strategy

E&P firms need strategic partners with the ability to provide proprietary technology, global project management and rapid response to address their specific produced water challenges and optimise operations and returns, writes ProSep’s CTO, John B. Sabey.

The aging of conventional wells and the boom in shale development have sparked a sharp increase in the volume of water produced by oil and gas production. Horizontal drilling and water-based hydraulic fracturing programmes onshore are far more water-intensive, while water cuts can be as high as 80-90% in wells in aged, depleted reservoirs.

The focus on produced water issues has grown in prominence 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.

In Norway, there are producers looking to reduce the amount of oil in water (OiW) to as close to zero as possible, as regulators and environmental agencies begin to monitor soluble components in addition to the free and dispersed oils (the small droplets of oil suspended in the produced water).

In the UK North Sea, the current performance standard for dispersed oil in produced water is set at 30 parts per million (ppm). In the US, the effluent limitations guidelines (ELGs) enforce limits of 29 ppm for offshore wells and impose a zero-discharge requirement for produced water onshore. Meeting such performance standards has become more challenging for exploration and production (E&P) firms as water production increases.

Growing market

Produced water can come from both conventional and unconventional wells. Typically, it 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, sulphates, radioactive elements and heavy metals.

The water already present in the reservoir (formation water) and the use of water injection techniques to aid the secondary recovery process (EOR – enhanced oil recovery) generates by far the largest volume by-product stream [see Figure 1], with some 21 billion barrels (bbl) of produced water generated each year in the US alone. With 1 bbl equating to 42 gallons, this figure represents about 57 million bbl – or 2.4 billion gallons – per day, according to the US National Energy Technology Laboratory (NETL).

The 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 use and re-use, reinjection or environmentally acceptable discharge.

NETL puts the water-to-oil ratio – i.e. the volume of water produced for every barrel of oil recovered – at between 5:1 and 8:1 in the US, and between 2:1 and 3:1 worldwide. Meanwhile, analysts at BCC Research believe that the water-to-oil ratio in North America will increase to 12:1 over the next 12 years – and 50:1 in the worst cases. With producers paying anywhere between $3 and $12 per barrel 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.

Case by case solution

The physical and chemical properties of produced water vary considerably depending on the geographic location of the field, the geologic formation, and the type of hydrocarbon product being produced. It is typically comprised of certain amounts of oil and solids, and a specific droplet size distribution.

The produced water will also have a specific chemistry, dependent on the chemical characteristics of the formation and the hydrocarbon. It may also include water from the reservoir, water previously injected into the formation, and any chemicals added during the production processes. Moreover, all of these properties and the produced water volume will vary throughout the lifetime of a reservoir.

As such, produced water is unique to every asset. Indeed, there could be two wells that are two miles apart and within the same formation that have totally different chemistries, oil, solids and droplet sizes. There could even be different produced waters coming into the same platform from two different wells, and it is not uncommon for these chemistries to mix together and compound processing issues such as scaling.

The water treatment and filtration requirements of upstream installations are therefore myriad and diverse. It is the characterisation and composition of the produced water that dictates the types of treatment technologies necessary to meet mandated limits. Flow rate dictates the size and quantity of the equipment needed, while the final specification and design is also dependent on how the asset operates currently, what condition it is in, production method and location. The most important consideration is the final destination/use of the produced water.

Technology evolution

Produced water can be treated through gravity separation, flotation, and filtration to physically or mechanically remove contaminants. Various proprietary technologies are employed, with their application dependent on the nature and volumes of the fluids being produced, asset type and location, and environmental legislation.

The first stage of the separation process relies on the effects of gravity and density difference, whilst the fluids remain within the separator. Here, 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, rather than any advanced technology-driven process within the tank itself.

Offshore, the requirement for a long residence time must be balanced against the footprint (size and weight) limitations placed on the separation tank. Several technologies are employed to eliminate oil droplets at the primary separation (gravity) stage, including hydrocyclones and plate coalescers. This is followed by flotation and filtration, with adsorbents and absorbents typically used after the tertiary (filtration) stage. Adsorbents and absorbents have seen development of innovative media solutions combining the two mechanisms of removal.

Offshore technology evolution has been driven both by regulation and by project economics. With floating production, storage and offtake facilities being billion-dollar propositions, there is huge benefit to reducing the weight of produced water solutions while ensuring high reliability to remove the need for redundancy, both of which translate to a smaller footprint.

Having met local mandates, there are producers in Norway that are now looking to exploit technology advancements to recover more crude. The CTour process is one such example. Based on extraction principals, it 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 oil and gas, the CTour process can yield a residual oil discharge as low as 2-3 ppm TPH while removing 90-95% of hazardous dissolved hydrocarbons.

Named in honour of the French scientist Cagniard de la Tour, who first discovered the phenomena of super critical fluids in 1822, the CTour process can treat large volumes of produced water at low weight, height, footprint, and capex and opex, while reducing overall chemical use. This represents a shift in produced water management, and future legislation based on this technology is anticipated.

A strategic concern

Certainly, there are several produced water technologies available today that are much better than the technology currently employed on some platforms. But with cost and compliance being primary factors dictating solution choice and dependent on whether you are talking to an E&P or engineering, procurement and construction (EPC) company, adoption of more innovative technologies will often be gradual.

Yet the fact is that technology choices made at the project outset can heavily influence long-term opex, and thus an asset’s overall profitability. For new builds, where produced water volumes will not be significant in the first few years of operation, there is a certain level of deduction necessary when it comes to assessing the technology requirement, which is where the experience of a produced water specialist can come to the fore in terms of reducing the potential cost of a retrofit later on versus installation from the start.

Likewise, if the operator intends to either decommission an existing asset or sell it on in the short-to-medium term, they may be unwilling to invest in a more expensive solution. However, selecting a lower cost solution purely because it does the job and meets the regulatory mandate can be risky. Issues can be encountered as produced water volumes rise, or should the chemistry of the reservoir change over time, so a capex-driven decision at the outset can prove false economy.

Historically, EPCs, and in some cases producers, have sought the lowest cost option whilst ensuring they are not exposed to long-term liability issues. However, analysts at IHS have warned that water management risks have increased rapidly in the past six years, 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 potentially risk lower production rates, damaged wells, and drilling and completion programmes can stall or be compromised. Regulatory penalties also apply should damage to the environment occur. All of this results in a breach in stakeholder faith.

Collaborative partnerships

Given that the produced water requirement must be addressed on a case by case basis, it is simply not possible for E&P companies to specify an optimum solution across their entire fleet. Most have hundreds if not thousands of installations, and every project is specific in respect of its produced water.

Often, EPCs must submit a solution tender based on the Front End Engineering Design (FEED), meaning the solution will be specified according to a formula based on the volume of water, amount of oil, droplet size distribution, specific gravity of the oil and water, and the mandated overboard discharge or re-injection specification. It can also be the case that the types of technologies to be provided are already specified. Ideally, the E&P company should conduct a pilot study on the specific produced fluids to ensure the proposed solution will provide the desired or required results.

In these situations, and where a supplier has pilot units available and hooks them up to a slip stream of the produced water, they are able to demonstrate the performance that can be achieved with proprietary technology. Often, it is not uncommon for operators to keep that solution on-board until a permanent solution is built and delivered.

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. From primary and secondary treatment, to filtration and fabrication, the provision of an optimum water treatment solution calls for experienced design engineers, field operators and technical service chemists – not to mention state-of-the-art manufacturing facilities and a global delivery capability.

Operators in particular would benefit from a single solution supplier, one that has partnerships and links with other key suppliers of additional components such as UF, NF, RO and other membranes and oil field chemicals needed to provide the optimal overall solution considering capex, opex and lifecycle factors. Here, smaller providers tend to be more nimble and responsive, both in maintaining effective partnerships and building a competitive solution based on the best available conventional and proprietary technologies.

Aftersales service support aspects are also important. Support specialists must be available online and via telephone 24/7 should an issue arise, with the supplier being able to rapidly deploy plug-and-play stop-gap solutions whether the asset is onshore or offshore, and provide long-term solutions when required. Solutions must also be scalable, with the modularity to be expanded and refined to meet the demand of increasing flows and changing chemistries of produced water as wells and reservoirs mature.

Historically, it used to be the case that E&P companies would dedicate minimum time and resources to the treatment, handling, and disposal of produced water. But in today’s risk-averse and environmentally-aware operating environment, the fact is that produced water contains contaminants that require time, money and resources.