A New White Paper Provides Critical Facts about Texas’s Growing Supply of Produced Water
Oil and water may not mix, but in Texas, they are deeply connected to success in oil and gas production. To maintain Texas’s energy-production dominance and continue decreasing reliance on foreign imports, Texas must continue to improve how produced water is managed.
The white paper—"Sustainable Produced Water Policy, Regulatory Framework, and Management in the Texas Oil and Gas Industry: 2019 and Beyond” —provides decision-makers, legislators and voters with producedwater facts and analysis. The information, which is presented in this article, helps determine where we are today, where we might be going, what we are doing right in Texas and what we can do better with the ever-increasing volumes of produced water associated with such landmark energy production.
Published by the Texas Alliance of Energy Producers (TAEP) and co-sponsored by the Independent Petroleum Association of America (IPAA), the white paper provides 10 recommendations to encourage the economical and sustainable recycling and reuse of produced water.
What’s at Stake
The United States has achieved historic global oil and gas production and largely accomplished the goal of becoming energy independent largely due to ever-expanding unconventional oil and gas production. U.S. net energy imports are at a 55-year low. U.S. exports of crude oil rose to average 2.9 million barrels per day in the first half of 2019, an increase of 966,000 barrels per day from the first half of 2018.
Texas has firmly established itself as the national leader in both crudeoil and natural-gas production. The Texas Permian Basin is the workhorse, comprising more than 40 percent of total U.S. production. As of September 2019, Permian oil production exceeded 4.4 million barrels of oil per day of the 12 million barrels of crude produced in the U.S.
The American economy is a huge beneficiary of this growth. A September Dallas Fed note puts the economic stakes into perspective. "The share of the upstream oil and gas sector in the level of U.S. nonresidential fixed investment doubled from 3.4 percent in the decade before the shale oil boom to an average of 6.4 percent since 2008."
The environment is sharing in the benefits of expanding gas production. Plentiful, well-priced natural-gas supplies increasingly fuel electricitygeneration capacity, generally replacing carbon-intensive coal-fired plants.
The national security benefits were on full display after the strikes on Saudi Arabia’s facilities. U.S. foreign policy is profoundly improved by the flexibility offered by domestic energy supplies. Walter Russell Mead reported in The Wall Street Journal that his colleague commented “the Permian saved Iran.” We also argue it is saving untold amounts of U.S. blood and treasure.
The Texas Permian Basin is the workhorse, comprising more than 40 percent of total U.S. production.
Energy and water are inextricably bonded in achieving this feat. To assure U.S. energy production dominance, it is imperative for the Texas oil and gas industry to continue to use water wisely and sustainably. Its management of produced water will be front and center over the coming years in this quest.
Water Demand and Produced Water Supplies Increase
Texas must simultaneously source large amounts of water for fracturing operations in water-stressed areas, while at the same time managing billions of gallons of produced water from onshore unconventional operations.
It’s important to put the industry’s water usage into context. The estimated statewide water use by the entire mining/oil and gas sectors remains less than 1 percent of all water used annually in Texas.
Water demand for fracturing operations will continue to increase due to the growing numbers of wells drilled and completed, coupled with the concurrent increase in fracturingfluid proppant intensity, well lateral lengths and well-design improvements. B3 Insight estimates in Table 1 that in 2017, the total statewide volume of produced water was more than 8.5 billion barrels. The Permian accounted for 66 percent of Texas’s produced water, whereas both the Eagle Ford and Haynesville produced 3 percent and the Barnett 6 percent.
Sourcewater produced-water volumes for five of the major Texas basins from 2014 to 2017 in Table 2 show the dramatic contrast between the Permian and the other major basins. As produced water increased in the Permian, it was decreasing in the Barnett and Eagle Ford during that time period.
The estimated statewide water use by the entire mining/oil and gas sectors remains less than 1 percent of all water used annually in Texas.
In the Permian Basin, home of nearly 70 percent of Texas oil production, B3 Insight forecasts producedwater output will reach a level of 8.5 billion barrels of water by 2024. Table 3 shows annual produced-water projections from 2019 through 2024. Gabe Collins from the Rice University Baker Institute indicates that from 2019 to 2023, Permian produced-water volumes could increase to more than 10 million barrels of water per day at an oil-production level of 6 million barrels of oil per day.
There is clearly a significant opportunity to close the water circle by matching increasing water demands with exploding produced-water supplies.
Hydraulic Fracturing Demanded New Water-Management Strategies
The tight formations where many Texas operators are currently producing oil and gas are not well-suited to accept waterflooding, a standard produced-water option in other formations. As a result, the move toward hydraulic fracturing in unconventional shale plays has resulted in a need for new water-management strategies.
The report describes different management strategies pursued by Pioneer, University Lands and Matador, as well as the midstream services XRI, Solaris, H2O and WaterBridge Resources. Going forward, operators will have a choice to keep water management in house or contract with a commercial midstream water-management company.
The scales may have tipped toward the midstreams by the dual advantages that the operator does not have to invest in infrastructure and the treated water may be less expensive than purchased fresh or brackish water. The midstream industry is ripe for consolidation, facilitated by private equitybased companies targeting companies with large continuous acreage and pipeline miles. Increased Produced-Water Recycle Produced-water management strategies have evolved dramatically over the past five years with increasing, albeit low, levels of treatment. Not only does produced-water recycle offset the need for fresh water for fracturing operations, treated produced water works better than fresh water.
As treatment costs have come down and freshwater prices have gone up, operators have been able to reduce operating costs. Even if the cost between fresh and produced water were on a par, using produced water rather than fresh reduces truck traffic and decreases associated environmental and infrastructure impacts.
Concerns remain regarding disposal-well capacity constraints due to new seismicity regulations, changing state requirements for seepage/evaporation ponds and reduced ability to reuse the treated water in basins where drilling and completion activities decline.
Up-to date data on current produced-water treatment and recycle volumes in Texas are variable and difficult to certify. Interviews revealed some operators are currently using more than 80 percent produced water to fracture new wells, while others have made it a priority to reuse 100 percent produced water.
The tight formations where many Texas operators are currently producing oil and gas are not well-suited to accept waterflooding, a standard produced-water option in other formations.
Other information sources indicate that recycle and reuse comprise such a small portion of the Texas water-management market (less than 1 percent to 5 percent) as to be negligible in the grand scheme of water handling. The 2019 Ground Water Protection Council (GWPC) report estimated reuse exceeds 10 percent in the Permian Basin, but is miniscule in the Haynesville Basin and is slightly more than 1 percent in the Eagle Ford Basin.
Regardless of the exact percentage, anecdotal evidence points to growing use of treated produced water in oil and gas operations. Produced-water recycle is likely to increase as the midstream industry matures and injection capacity is unable to keep pace with production.
Regarding technology, we conclude that current, as well as emerging, tertiary treatment technologies support costeffective recycle in the oil and gas fields. However, there are no “silver bullet” technologies on the horizon that will lower costs to a degree that would make disposal wells obsolete. Texas must maintain its disposal-well capacity.
Drivers and Headwinds
We see that the “drivers” encouraging operators to embrace recycle in their produced-water management strategies include increasing fracingwater demands, increasing freshwater and trucking costs, decreasing treatment costs, local climate and geologic realities, company culture and recycle policies, and increasing volumes of produced water to support the growth of the midstreams.
On the flip side of the coin, there are headwinds—issues that are hard to put a price tag on, but nonetheless, factor into water managers’ decisions. Environmental, community concerns on housing and education, political, civil liability and regulatory issues factor into whether operators opt for treatment over direct disposal.
Leading the Way on Its Regulatory and Legal Frameworks
Texas’s well-developed regulatory and legal framework demonstrates its foresighted leadership on water issues. Texas continues to make legislative and regulatory strides to ensure authority keeps pace with the rapidly evolving upstream and midstream business models.
There was significant legislative activity in the 86th legislative session. Due to existing federal National Pollutant Discharge Elimination System (NPDES) requirements, few producedwater discharges are authorized in Texas. HB2771, passed in May 2019, places the statutory authority of NPDES under the Texas Commission on Environmental Quality (TCEQ) to issue permits for produced-water discharge. The law also directs the TCEQ to seek federal NPDES delegation from the Environmental Protection Agency (EPA) to Texas.
The agency convened a stakeholder meeting to discuss implementation tasks, schedule, elements of delegation application, and permitting and compliance issues.
The Texas legislature has long held that ownership of water is not regulated the same way as oil-field waste, which includes produced water. HB 3246 became law on Sept. 1, 2019, amending the natural-resources code such that oil-field waste is the property of the party to which the waste was transferred for treatment or beneficial reuse. This ownership clarification is an important step forward for recycling in Texas.
Unfortunately, recycle-incentive initiatives did not pass. Bills were considered that involved some percentage of severance or other tax relief for oil and gas operators in exchange for the reuse of treated produced water. HB 3067 would have encouraged recycling of produced water of certain salinity levels by ensuring a severance tax credit for treated produced water that is sold or lawfully discharged.
HB 3717/SB 1919 recommended an oil and gas production tax credit for producers that provide treated produced water to aquifer storage and recovery project operators.
While the incentive proposals did not cross the finish line in the 86th legislative session, Texas will sponsor studies on recycling’s economic impacts and hold hearings over the next two years on incentives.
Discussions surrounding eminent domain with regard to pipelines went unresolved, but it is anticipated that regardless of what’s in the pipe, costs of pipeline transportation will likely rise. Infrastructure concerns in local communities were addressed by earmarking about $250 million for infrastructure improvements in oil-field areas.
Figure 1 presents the white paper’s 10 recommendations for the sustainable use of produced water under three guiding thoughts.
First, Texas should maintain leadership and control over produced-water management within its state borders. Second, Texas must continue to amend its laws, regulations and practices to encourage innovation and increase treatment of produced water.
Third, the federal government must update its rules and continue engagement with its state partners so that state efforts may flourish.
Texas continues to make legislative and regulatory strides to ensure authority keeps pace with the rapidly evolving upstream and midstream business models
Texas has shown it is capable of safely regulating its oil and gas industry and should maintain control over its produced water.
• The preservation of the Resource Conservation and Recovery Act (RCRA) exemption for oil-field waste is the foundation for almost all Texas’s oil-field waste-management practices. The EPA conducts a determination every three years, determining in April 2019 that the existing state frameworks are handling the wastes effectively.
The RCRA exemption paves the way for Texas to maintain primary jurisdiction over produced water. It’s imperative to maintain this exemption.
• The delegation of oil-field NPDES authority to Texas could expand and streamline reuse options for produced water in the state. The achievement of NPDES delegation from the EPA to the state of Texas would be a huge step in paving the way to beneficial reuse and other market-oriented outcomes for produced water.
• Texas should maintain state jurisdiction over produced-water pipelines rather than ceding jurisdiction to federal agencies like the Pipeline and Hazardous Materials Safety Administration (PHMSA).
Expansion of federal pipeline regulations that would expand PHMSA jurisdiction over produced-water transportation would add burdensome and likely unnecessary regulations while having little positive impact on the state’s ability to oversee produced- and recycled-water pipeline operations.
Texas must continue to keep pace with the times by updating its laws, regulations and practices regarding water management. Texas would be prudent to:
• Increase coordination between energy-producing states and state and national associations to share expertise and lessons learned, as well as to homogenize policy as much as practicable. It is imperative for the industry to support state and national organizations like the Groundwater Protection Council (GWPC) and the Interstate Oil and Gas Compact Commission (IOGCC), who can provide forums for discussion ensuring the industry can move forward in step on the issues.
• Revise necessary statutes and regulations on the handling of produced water as technology and the market evolve. One such area may be spill reporting.
• Prepare a road map for the beneficial reuse of produced water. The industry should maintain its focus on operations and sound produced water management in the oil field. The government’s role can be to sponsor research on knowledge gaps, encourage reuse by updating regulations and issue permits for pilot studies on uses outside the oil field. Also, a solid and repeatable funding mechanism to defray the cost of these academic and scientific studies would benefit all.
• Develop incentive mechanisms to help lower the costs of treating produced water, which will defray costs and encourage water recycling. There have been murmurs in the Texas legislature surrounding an interim study of the effect of incentives on produced water recycling.
• Knowing that good data is the foundation of good policy and that up-to-date data is not currently available to the public, Texas should encourage the appropriate organization, such as a university or other industryled group, to collect and provide produced-water supply, recycling and reuse data. It is important that no tax regime be attached to this endeavor. It would also be helpful for the industry to agree on standardized produced-water terminology.
From a federal perspective, the government must continue to update the appropriate rules and regulations and should continue the discussions and studies with stakeholders. Specifically, it would be beneficial to:
• Eliminate the 98th meridian policy, a geographic marker used by the EPA as a tool to separate discharge permitting under NPDES rules that disallows onshore discharges east of the 98th. This is an anachronistic division, not reflective of the current technological advances in recycling nor the need for site-specific permit conditions independent of broad national controls.
• Enhance coordination between states and federal agencies, similar to the Memorandum of Understanding between New Mexico and the EPA. Efforts like these effectively bring people to the table in common study and constructive critique that would be beneficial for Texas.
Texas took an early lead in recognizing the potential value of recycling produced water and began updating its regulatory framework in 2013. It is now time to further improve the regulatory framework, with careful consideration of incentives for recycling, infrastructure improvements, pilot projects to study potential impacts of produced water reuse, improved data availability and updated metrics, and federal delegation of key statutory authorities.
Produced water recycling in Texas is poised to expand with the right statutes, regulatory framework, civil law and economic incentives.
Concluding Thoughts: Moving the Needle toward Beneficial Reuse:
Years ago, the question was whether produced water was “an asset or a waste.” Today, we know produced water is both. The question remains: What is needed for produced water to become a valuable commodity with beneficial use outside the oil and gas industry?
Future advancements in desalinization technology may lead to economically competitive solutions and allow for beneficial reuse outside the oilfield. To “move the needle” on beneficial reuse, the Texas government has a role to play in sponsoring research on environmental concerns and creating supporting legislative and regulatory frameworks.
Will we be able to embrace the technology and craft the regulatory framework that allows us to take advantage of the opportunities that produced water may provide? The answer lies before us.
2. TODAY IN ENERGY: Thursday, Oct. 3, 2019
3. https://www.dallasfed.org/research/economics/2019/0924 “Oil and Gas Sector Increasingly Influences U.S. Business Fixed Investment,” Karel Mertens, Grant Strickler and Martin Stuermer, Sept. 24, 2019
4. https://www.wsj.com/articles/dont-ruleout-war-with-iran-11569279312, “Don’t Rule Out War with Iran,” Walter Russell Mead, Wall Street Journal, Sept. 23, 2019
5.Collins, Gabriel. 2019. Slide 4. https:// www.bakerinstitute.org/media/files/ files/49b5dc27/collins-pbwiec-2019- permian-oilfield-water-midstreamconsolidation-and-integration-loom-21- february-2019-final-version-1.pdf.
6.Produced Water Report: Regulations, Current Practices and Research Needs. 2019. Accessible at www.gwpc.org
Authored by Blythe Lyons, John Tintera & Kylie Wright