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Gabriel Collins

Gabriel Collins

Gabriel Collins is a licensed Texas attorney and basic materials specialist who proudly hails from the Permian Basin. He runs Caracal Commodities, LLC and also…

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Don't Ask What Wastewater Costs But What its Worth

Rigs

Oilfield produced water is an abundant resource in Texas, with a minimum estimated volume of 20 million barrels produced each day (actual production may now exceed 25 million bpd). This is roughly equal to the combined net water use of Austin, Dallas, El Paso, Fort Worth, Houston, and San Antonio combined in 2014.

Yet E&Ps have historically viewed produced water largely as a commercial and legal liability that must be offloaded in order to enable oil production. Indeed, even in the present oil price downturn, producers continue to cite reducing water disposal costs as one of the steps they are undertaking to reduce production costs and stay competitive.

Produced water handling and disposal costs significantly affect OPEX, profitability, and overall economic competitiveness. Thus, there are strong incentives to flip produced water from a cost-center into a saleable, revenue-generating commodity, or at least make it cost-neutral on E&P balance sheets.

Logistical challenges remain but the confluence of five key factors strongly suggests that it now time to ask not what produced water costs, but rather, what is it worth? With its relatively friendly legal regime on oilfield fluids recycling and title transfer, Texas is a favorable location to explore the concept and with its globally-significant activity level, the Permian Basin is the ideal play to focus on first.

Key factors that could drive a produced water paradigm shift:

1. Increasing political pressure to minimize the use of fresh water for fracs;
2. Advancing water treatment technology;
3. A more permissible legal and regulatory environment;
4. Industry is favoring slickwater frac designs that are less sensitive to water salinity as well as developing frac chemistries that mitigate the effects of formerly troublesome ions found in many produced waters;
5. The proliferation of industrial-scale water handling infrastructure in the Permian and Delaware Basins, including networks with two key characteristics: (A) water handling system-wide capacities that could feasibly be scaled up to a million bpd and (B) system owners who suggest they are willing to consider allowing third-party access to their systems.

Potential Pricing Models: Cost-Based and Variable, With Immense Space for Innovation and Creative Allocation of Risk

The produced water sales discussion centers on two interrelated pricing models: cost-based and variable (i.e. dynamic) pricing. In simplest terms, cost-based pricing presumes a party selling produced water would not want to sell it at a price less than what it costs to gather the water, treat it to a frac-usable standard, and then transport it to an end-user’s pond.

The analysis here assumes sale to a third-party, with a 10 percent profit margin built into the final delivered price of the treated produced water. If the operations are instead handled by a dedicated midstream operator–an evolution the author believes is likely–the desired profit margin would likely rise, but could be offset by greater economies of scale. Related: China’s Oil Majors Are Burning Through Oil Reserves

The author acknowledges that for high-volume users who seek to procure longer-term water supply agreements, parts of the cost chain could vary. For instance, a user located near the treatment facility could obtain water via a short distance, high volume layflat hose. Such a purchaser could also seek volume discounts or consider purchasing dedicated capacity in the facility in exchange for a discount in the price of water supplied to it. Many deal permutations will likely arise if and when the trade develops.

Exhibit 1: Cost-Based Price of Produced Water versus Alternative Supply Options

(Click to enlarge)

Exhibit 2 (below) lays out the assumptions made in the produced water cost calculations, as well as their sources. The bottom line is that the biggest portion of the produced water’s cost is the treatment phase. Preliminary data suggest that a combination of infrastructure scale, along with inbound water quality, exert particular influence on treatment costs per barrel. For instance, as of 21 June 2016, Approach Resources reported a treatment cost of $1.50/barrel for produced water handled in its 329,000 barrel Pangaea treatment center. In contrast, Apache has reported a treatment cost of only $0.29/barrel in its Barnhart recycling system, which has a 1.5 million barrel capacity.

As Exhibit 1 shows, produced water treated at a cost closer to the Apache figure likely means that recycled produced water could be supplied by pipeline or layflat hose to locations within 10 miles of the recycling center at an “all-in” delivered price competitive with high-volume non-trucked freshwater, brackish water, and municipal effluent. Please note that this model credits the skim revenue against other treatment costs, so water with lower recoverable hydrocarbon content will have a less favorable cost structure.

Exhibit 2: Produced Water Sale Cost Model

Variable pricing entails creating a more dynamic system that moves in response to real-time supply and demand forces. Generally, the cost-based price of the produced water would set the floor, but prices could rise significantly beyond this level if demand warranted. The all-in delivered cost of rapid response marginal supplies such as trucked freshwater would likely establish the upper bound for how high prices might go in a variably priced tight market situation.

Two core challenges would need to be overcome for variable pricing of produced water sales to function in practice. First, operators and service companies will need to share much more significant amounts of real-time data on water supply and demand in areas with infrastructure capable of redirecting water flows to meet evolving needs. Second, produced water gathering, treatment, delivery, and disposal infrastructure will need to be more tightly integrated to reduce the cost and time of water movement and maximize potential arbitrage opportunities.

Inelastic supply and demand pose surmountable challenges

Produced water systems are relatively demand-inelastic on the gathering system side. An operator is almost certainly not going to choke back an oil or gas well or open it up wider if demand for produced water rises because the well’s primary purpose is to produce hydrocarbons, with the produced water being a byproduct commodity.

Frac water demand, on the other hand, is lumpy,” with slow periods punctuated by spurts of intense demand as operators fill frac ponds. Treatment time and most importantly, storage capacity for treated produced water that is ready to sell, will dictate how responsive a system is to frac demand. A recent published SPEpaper showed that Apache’s pilot field plant for treating and reusing produced water in the Barnhart area of Irion County, Texas featured a residence time of 60-100 minutes in each of the system’s four holding and treatment tanks. On this basis, it is reasonable to assume that a given barrel of water put into a chlorine dioxide-based treatment system would have a residence time of at least 5-6 hours.

Large volumes of treated water stored in tanks or a pond would offer a faster response time, albeit at the cost of building and maintaining the storage structure. Our conversations with field sources suggest that a 500kb lined impoundment costs roughly $500-600k to construct in many parts of the Permian Basin, with a lined million-barrel pond likely to cost closer to $1.5 million. Once a lined impoundment is built–and covered to reduce costs imposed by evaporation losses–maintenance costs are generally low per unit of water stored. Such impoundments also offer the owner the option of integrating additional non-traditional water supplies such as Santa Rosa brackish water and municipal effluent into the treated produced water stream. Related:The Best Way To Unlock Canada’s Crude Exports

Blending also helps ensure a consistent quality water stream, since the chemical composition of incoming produced water streams may vary significantly well-by-well. Large operators are already doing this in their proprietary loops. For instance, Pioneer Natural Resources blends its recycled produced water in the Midland Basin with treated municipal effluent purchased from the City of Odessa, while Apache blends treated produced water with Santa Rosa brackish water in its Barnhart system in Irion County. To that end, Apache reports that in 2013 in Irion County, it used 10 million barrels of brackish groundwater blended with 3.1 million barrels of treated produced water.

Operators could also blend freshwater volumes with produced water to yield an acceptable frac fluid. Blending decisions would likely be taken at the operator level on a well-by-well basis that took into account factors including, but not limited to: formation characteristics, frac chemistry constraints, what sources of water are timely available and in what quantities, and what their respective costs/prices are.
Payout for gathering, treatment, storage, and distribution assets is likely to be reasonably rapid in active areas, since the all in cost of produced water disposal via deep injection is likely to be at least $1.00 per barrel even in SWD facilities with pipeline access (at least $0.50/bbl in injection fees, closer to $0.75-0.85/bbl in many cases, plus pipeline transport costs). A simple “back of the napkin” analysis assuming an initial gathering/treatment/distribution infrastructure capital investment of $35 million, an avoided disposal cost of $0.50/bbl, and an incoming volume of 100 kbd of water suggests the following payback times:

Scenario A: Provision of treated water at the cost of gathering, treatment, and delivery, with no added profit margin. Payback in Year 7 at 75 percent utilization and Year 9 at 50 percent utilization.

Scenario B: Sale of Treated water at a profit margin of $0.05/bbl above cost. Payback in Year 6 at 75 percent utilization and Year 8 at 50 percent utilization.

Scenario C: Sale of Treated water at a profit margin of $0.10/bbl above cost. Payback in Year 6 at 75 percent utilization and Year 8 at 50 percent utilization.

What if produced water demand drops off…

Connectivity to disposal assets helps mitigate risks caused by sudden drops in demand for treated produced water. Basically, if demand drops off and the treatment plants slows runs, excess incoming water can be re-routed to the disposal wells and injected.

One key challenge here is that while having a pipeline with spare capacity to access disposal wells is in the produced water recycler’s interest, it is not in the interest of an SWD operator to have idle capacity in his lines. One possible solution would be for the produced water recycler to pay the SWD operator for dedicated capacity. Another would be to create a traded capacity market where space on the inbound SWD line goes to the highest bidder. Another is for the recycler to construct sufficient captive SWD capacity to dispose of excess water during down periods–much as a refiner or gas processor maintains flare stacks to dispose of product during operational disruptions.

The most expensive water…

Once a frac is underway, water demand also becomes extremely unresponsive to price changes. The reason is simple–when the pit is filling up and the service provider is spooling up his pumps, the most expensive water is that which never makes it to the pit. In most cases, an operator would rather pay $5.00/bbl to get the pit topped off and the job pumped right than to insist on paying $0.50/bbl for water that never shows up. High-reliability and predictable produced water sources would help diversify supplies and alleviate these risks.

Likely Future Directions

If produced water becomes a saleable commodity, this will likely help catalyze the development of a more interconnected oilfield water infrastructure in the Permian Basin. One key issue is the heightened liability risk incurred by moving high-salinity produced water in pipelines, since pipeline ruptures tend to cause large spills.

Producers are likely to have varying risk appetites for moving saline water into large-scale treatment facilities and then re-distributing it out to frac ponds via pipeline, layflat hose, and in some cases, trucks. This creates a logical business space for a water-oriented midstream operator, whose business model generally already contemplates the risk of owning and transporting saline water.

It is likely that many operators in Texas will welcome the opportunity to transfer ownership of produced water to a midstream provider as rapidly as possible. Under Section 122 of the Texas Natural Resources Code, once the produced water is transferred with the intent that the midstream provider will treat it and send it to another party for drilling for, or production of, oil and gas, the original producer will generally no longer face tort liability for injuries caused by the produced water.

The “Holy Grail” is a large-volume open access produced water gathering and recycling system with significant geographical coverage that can also integrate other alternative water sources such as brackish water and municipal effluent. Sufficiently large and connected infrastructure can serve as a “magnet” for produced water from a range of operators by creating the ability to sell what was formerly an expensive waste product. As recycling and re-sale via industrial-scale systems with third party access become more cost-effective than investing in proprietary disposal and/or recycling loops, the Permian Basin produced market could take off rapidly and transform operational cost structures.

By Gabriel Collins for Oilprice.com

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Leave a comment
  • Lee James on August 27 2016 said:
    How close are we, really, to this Holy Grail solution? Will we move on from our current inject-and-forget disposal method for thoroughly foul process water?

    Good to look closely at all of the costs associated with bringing in increasingly "tough" oil. We do need to be realistic about the high cost of source-rock fracturing, deep-water wells, and oil from tar sand. Technology keeps bringing the crude up, but it ain't cheap.

    What is our energy future?

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