Introduction
America’s oil and gas industry produces huge volumes of saltwater in lockstep with oil and gas production. Most hydrocarbon reservoirs contain water mixed with the hydrocarbons – it’s this water that is unavoidably produced to the surface. In addition to reservoir water, oil and gas producers sometimes add water to the subsurface environment by high pressure fracture treatments – fracking – and this water is eventually returned to the surface. Oilfield waste water, whether reservoir water or frack water, is almost all saltwater with salinities higher than sea water; there are few commercial uses for this water except to re-inject into the original reservoir to maintain pressure. If the produced water could be treated to make it less salty, it could be used to water crops, water livestock, and used for municipal water supply. An economic system is the promise of the countless treatment technologies making the rounds of oil and gas trade meetings and investment conferences. Do these technologies deliver on the promise? Is there a market for these technologies? What questions should a potential investor ask to evaluate a start-up treatment company?
America’s oil and gas industry produces huge volumes of saltwater in lockstep with oil and gas production. Most hydrocarbon reservoirs contain water mixed with the hydrocarbons – it’s this water that is unavoidably produced to the surface. In addition to reservoir water, oil and gas producers sometimes add water to the subsurface environment by high pressure fracture treatments – fracking – and this water is eventually returned to the surface. Oilfield waste water, whether reservoir water or frack water, is almost all saltwater with salinities higher than sea water; there are few commercial uses for this water except to re-inject into the original reservoir to maintain pressure. If the produced water could be treated to make it less salty, it could be used to water crops, water livestock, and used for municipal water supply. An economic system is the promise of the countless treatment technologies making the rounds of oil and gas trade meetings and investment conferences. Do these technologies deliver on the promise? Is there a market for these technologies? What questions should a potential investor ask to evaluate a start-up treatment company?
Treatment Versus Disposal
Produced saltwater is injected into deep wells as part of standard and customary industry practice. Costs of deep injection are quite low because large volumes are promised on a daily basis but of course costs vary from basin to basin and company to company. A well that is capable to injecting thousands of barrels every day at low pressures can dispose of a single barrel of saltwater for much less than $0.10. In the mid-range of costs, many commercial disposal wells in Texas and Oklahoma charge $0.40 to $0.80 per barrel to dispose of saltwater. At the other extreme some basins have very few suitable injection zones suitable for saltwater disposal and a company might be forced to truck produced saltwater many miles away, this could translate into a disposal cost over $2.00 per barrel. This is the range of real-world costs for disposal of saltwater in the oilfield.
Produced saltwater is injected into deep wells as part of standard and customary industry practice. Costs of deep injection are quite low because large volumes are promised on a daily basis but of course costs vary from basin to basin and company to company. A well that is capable to injecting thousands of barrels every day at low pressures can dispose of a single barrel of saltwater for much less than $0.10. In the mid-range of costs, many commercial disposal wells in Texas and Oklahoma charge $0.40 to $0.80 per barrel to dispose of saltwater. At the other extreme some basins have very few suitable injection zones suitable for saltwater disposal and a company might be forced to truck produced saltwater many miles away, this could translate into a disposal cost over $2.00 per barrel. This is the range of real-world costs for disposal of saltwater in the oilfield.
Costs of
saltwater treatment are difficult to determine with any certainty. In the
Powder River Basin of Wyoming and Montana a fair amount of the coalbed methane
(CBM) produced water is mildly salty 2,000 to 3,500 mg/L total dissolved
solids) and can be treated to irrigation standards for approximately $0.20 to
$0.50 per barrel. In the Ft. Worth Basin of Texas, frack flow-back water can be
treated for re-use at the rate of approximately $5 to $6 per barrel, a rate
that is approximately one hundred times higher than the City of Ft. Worth
currently charges oil and gas operators for municipal water used in fracking (http://fortworthtexas.gov/uploadedFiles/Gas_Wells/SWD_questions.pdf). It’s clear that treating costs
vary depending upon the salinity of the saltwater, its location and its
ultimate use.
Treatment Technologies
In the past 20 years, the technology of saltwater treatment has progressed, driven by municipal desalination projects around the globe; technology continues to become more efficient and lower in cost. The US Department of Energy maintains a comprehensive website (http://www.netl.doe.gov/technologies/pwmis/techdesc/index.html) that supplies water treatment data to the oil and gas industry. The website contains basic information on new and existing technologies as well as data on oilfield installations. What is the most common form of municipal desalination technology – reverse osmosis – has not proven itself to be feasible for oil and gas waste water because of the presence of oil and grease in the water, which fouls the membranes in the Reverse Osmosis (RO) units. Even CBM water, which contains no liquid hydrocarbons in the reservoir, cannot be treated with RO because the pumps used to produce the water are standard oilfield pumps that contain and leak lubricants and hydraulic fluids. Pre-treatment techniques, however, continue to improve and in the end RO technology may prove successful.
In the past 20 years, the technology of saltwater treatment has progressed, driven by municipal desalination projects around the globe; technology continues to become more efficient and lower in cost. The US Department of Energy maintains a comprehensive website (http://www.netl.doe.gov/technologies/pwmis/techdesc/index.html) that supplies water treatment data to the oil and gas industry. The website contains basic information on new and existing technologies as well as data on oilfield installations. What is the most common form of municipal desalination technology – reverse osmosis – has not proven itself to be feasible for oil and gas waste water because of the presence of oil and grease in the water, which fouls the membranes in the Reverse Osmosis (RO) units. Even CBM water, which contains no liquid hydrocarbons in the reservoir, cannot be treated with RO because the pumps used to produce the water are standard oilfield pumps that contain and leak lubricants and hydraulic fluids. Pre-treatment techniques, however, continue to improve and in the end RO technology may prove successful.
The most
successful technology for oilfield application has been ion exchange, which is
able to tolerate small amounts of oil and grease and can treat water with a
range of salinities. Treatment technologies are discussed in detail within the
DOE website as well as many other publications.
Treatment Wastes
All the treatment technologies available to the oil and gas industry have a waste stream – desalination does not destroy salts. Treatment accepts water with salts in solution and produces two streams – a low salinity water phase that is acceptable for a specific use whether this is oilfield re-use, irrigation, or drinking, and a waste water phase that is much higher in salinity than the feed-water. It is the ratio of the volume of the product to the volume of the waste that determines the salinity of the waste stream. The waste stream must be disposed of in a safe and economical manner – usually deep injection down disposal wells.
All the treatment technologies available to the oil and gas industry have a waste stream – desalination does not destroy salts. Treatment accepts water with salts in solution and produces two streams – a low salinity water phase that is acceptable for a specific use whether this is oilfield re-use, irrigation, or drinking, and a waste water phase that is much higher in salinity than the feed-water. It is the ratio of the volume of the product to the volume of the waste that determines the salinity of the waste stream. The waste stream must be disposed of in a safe and economical manner – usually deep injection down disposal wells.
Disposal
costs were discussed at the top of this blog and those numbers are seen when
disposing desalination wastes except that in some EPA regions, water treatment
wastes – even for treating oil and gas produced water – are industrial products
that must be disposed into industrial (Class 1) disposal wells. Class 1
disposal carries higher regulatory burden and higher costs to the disposer.
Treatment Wastes as Commodity
Constituents of the treatment waste stream are often touted as salable commodities but the demand for these chemical compounds are in fact miniscule compared to the huge volumes of salts produced by one treatment plant.
Constituents of the treatment waste stream are often touted as salable commodities but the demand for these chemical compounds are in fact miniscule compared to the huge volumes of salts produced by one treatment plant.
Treatment Technology Investment
Opportunities
A great deal of time, effort, and money is being devoted to treating waste water in order to satisfy a huge need. For example, oil companies developing unconventional reserves need large volumes of water to frack each producing well, water that currently can’t be re-used. Regional electrical power plants use large volumes of water in their cooling towers and often this water cannot be returned to the environment without treatment. The need for suitable water is large and industrial operators are spending millions of dollars to find treatment technologies that make economic sense. The opportunity for new treatment technologies is clear as are the opportunities for their investors. It must be obvious what these start-up technologies offer to the oil and gas industry and to investors.
A great deal of time, effort, and money is being devoted to treating waste water in order to satisfy a huge need. For example, oil companies developing unconventional reserves need large volumes of water to frack each producing well, water that currently can’t be re-used. Regional electrical power plants use large volumes of water in their cooling towers and often this water cannot be returned to the environment without treatment. The need for suitable water is large and industrial operators are spending millions of dollars to find treatment technologies that make economic sense. The opportunity for new treatment technologies is clear as are the opportunities for their investors. It must be obvious what these start-up technologies offer to the oil and gas industry and to investors.
Important Questions Investors
Must Ask
A prospective investor must be willing to perform sufficient technical due diligence on the new treatment company. At minimum several questions must be answered in writing and with sufficient technical details, preferably by way of third-party documents. The new company may require that the prospective investor sign a confidentiality agreement (CA) prior to the exchange of proprietary information. Following are examples of the type of questions that should be addressed to the company seeking project-funding:
A prospective investor must be willing to perform sufficient technical due diligence on the new treatment company. At minimum several questions must be answered in writing and with sufficient technical details, preferably by way of third-party documents. The new company may require that the prospective investor sign a confidentiality agreement (CA) prior to the exchange of proprietary information. Following are examples of the type of questions that should be addressed to the company seeking project-funding:
1.
What kinds of water treatment
does your company employ in its process? The new company will be able to give a great deal
of information, most of which will not be proprietary or exclusive to this
company. A thorough answer to this question is absolutely essential to
continuing the discussion. Pretreatment must also be described by the new
company.
2. What
type of oil and gas waste water does your treatment target? Produced water across the United
States varies between 1,000 mg/L to 250,000 mg/L and treatment requirements
will be much different. If the new company does not have a definable target
feedstock for its technology, the company has a fatal misunderstanding of
oilfield waste water. The target waste water must be closely defined in terms
of chemical contents and accurate estimates of its extent both volumetrically
and geographically. This is another make-or-break question for a new start-up
company.
3. What
sort of bench-tests and field-tests have you performed and can you supply data
on the tests?
Their answer to this question classifies the new company as a blue-sky
opportunity that has little substance, a start-up with proof-of-concept lab
data, or a company with true field experience and useable operating data. These
three kinds of company will have different financial needs and should be
willing to offer different deals to prospective investors.
4. What
are the power and chemical demands for your process? The first step in analyzing the
economics of each process is to determine the costs of the process. Bench-scale
tests are informative but long-term field-tests are required at some stage of
the project.
5. What
is the CAPEX cost of the unit being designed? Obviously the capital cost of the
treatment unit is necessary to determine the economics of the process. A new
company with only lab tests will lack good data on capital costs.
6. What
wastes are produced by your process and how will they be managed in the short
and long term? Waste
management is another vital piece of measuring economics of a new process. If
the company has a poor understanding of its waste, it could be leaving
investors vulnerable to environmental liabilities and punishing costs in the
future.
7. How
long are field-trials expected to continue and when will commercial
installations take place? The
new company must have a very good idea how many field units will be deployed and
how long the trials will last. If the process is sensitive to ambient
temperatures, the trials should take place in all four seasons in areas where
the target wastes are produced. Field trial design is an indication of the
knowledge and thoroughness of the new company.
After
the new start-up company has given answers to these and other questions by the prospective
investor, a good evaluation can be made of the technical power of the company,
what kind of testing still needs to be done, what kind of test data needs to be
collected, and what level of financing is required. Of course the investor will
also perform due diligence on the financial aspects of the new company and its
principals. Only then will both parties be on the same level and only then can
investment arrangements be discussed.
The Authors:
Marian M. Smith, Ph.D., University of South Carolina (Geology) is a partner in Odin Oil and Gas, LLC, in Oklahoma City, OK. Dr. Smith has expertise in reservoir geology and image analysis. For most of her career she was an educator at all levels from graduate school geology courses at Michigan Technological University to the teaching of science in middle school in South Carolina. At present she is combining her background in research and teaching to work as a consultant with Dr. Langhus at Odin Oil and Gas, LLC.
Bruce G. Langhus, Ph.D., is a petroleum geologist with over 45 years' experience in oil and gas business including water-flood design and operation; Class I, II, and III disposal well location, permitting and operation; and injection well remediation.Dr. Langhus has been the Class II Program Manager in Oklahoma, the second largest UIC program in the country.He was a founding partner of ALL Consulting, a successful geotechnical consultancy in Tulsa, OK.Dr. Langhus is now part of Amerex Resources, operators of disposal facilities in Texas, Oklahoma, Montana, and North Dakota.
Cost-effective solutions for flow back water treatment and produced water treatment will play and important role in the economics and environmental sustainability of unconventional oil and gas production. It is estimated that it takes it takes somewhere between 70-140 billion gallons of water per year to support hydrofracking 35,000 gas wells at the current annual rate in the U.S.
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