Month: March 2021

Injection and Disposal Wells

Disposal wells may be used to inject mineralized water produced with oil and gas into underground zones for the purpose of safely and efficiently disposing of the fluid. Typically, the underground interval is one that is not productive of oil and gas. In some cases, however, the disposal interval is a productive zone from which oil or natural gas has been produced or is currently produced. In either case, the disposal interval must be sealed above and below by unbroken, impermeable rock layers.

Injection wells inject fluids into a reservoir for the purpose of enhanced oil recovery from the reservoir. The vast majority of wells in Texas are injection wells. Operators use injection wells to increase or maintain pressure in an oil field that has been depleted by oil production and also to displace or sweep more oil toward producing wells. This type of secondary recovery is sometimes referred to as water-flooding.

Texas is the nation’s number one oil and gas producer with more than 315,618 active oil and gas wells statewide according to oil and gas well proration schedules (as of June 30, 2015). Injection and disposal wells are also located throughout the state to improve oil and gas recovery and to safely dispose of the produced water and hydraulic fracturing flowback fluid from oil and gas wells. Texas has more than 54,700 permitted oil and gas injection and disposal wells with approximately 34,200 currently active as of July 2015. Of these 34,200 active injection and disposal wells, about 8,100 are wells that are used for disposal, the remainder (about 26,100) are injection wells.

What chemicals are found in the fluid injected into injection and disposal wells?

The overwhelming majority of injected fluid is oilfield brine, which is also sometimes referred to as produced water. Oilfield brine is the water, with varying levels of salinity that is found in the same geologic formations that produce oil and gas. This produced water comes up simultaneously with the production of oil and gas. However, small quantities of substances used in the drilling, completion and production operations of a well may be mixed in this waste stream. Some of these materials that may enter into the oilfield brine waste stream are minor amounts of drilling mud, fracture fluids and well treatment fluids. Also, because the produced water is associated with crude oil and natural gas, small amounts of residual hydrocarbons may also be found in the produced water.

What are the construction standards for a disposal well?

Commission rules for the construction of all oil and gas related wells, including injection or disposal wells, are intended to protect groundwater and require multiple layers of cement and steel to ensure that usable quality water is protected. Disposal wells inject saltwater into underground formations, often over a mile in depth, into sub-surface zones that already contain naturally occurring saltwater. In contrast, wells that supply fresh water can vary in depth throughout the state, but generally range from no deeper than a few hundred to a thousand feet.

In accordance with 16 TAC §3.13 (Statewide Rule 13), a disposal well’s construction standards for disposal wells typically require three layers of casing to ensure groundwater is protected.

The first protection layer is surface casing; a steel pipe that is encased in cement that reaches from the ground surface to the base of the deepest usable quality groundwater. Surface casing also acts as a protective sleeve through which deeper drilling occurs.

The second protection layer is the production casing;a pipe inside the surface casing and extending to the well’s total depth and permanently cemented in place. Wells may also be constructed with an intermediate casing between the surface casing and the production casing.

The third protection layer is the injection tubing string and packer that conducts the injected water down through the production casing to perforations at the bottom of the well to inject the water into an underground formation. The tubing/packer assembly creates an isolated annulus that is monitored to detect any pressure changes that may indicate a leak or other type of mechanical issue and allow the well to be shut down before any harm could occur. [Also see 16 TAC §3.9 (9)(A) and §3.46 (g)(1).

How are these wells monitored and inspected?

Operators are required to report to the Railroad Commission monthly average injection rates, total monthly volumes, and maximum wellhead injection pressures for wells, both to assure the injection rates and pressures are consistent with amounts specified in the Commission’s injection/disposal permit and to signal if a significant pressure change occurs. If there is a significant pressure change on the well or if other monitoring data indicates the presence of leaks, an operator is required to notify the RRC District Office within 24 hours. If there is a problem, the Commission requires wells to be shut in and repaired.

The Railroad Commission inspects commercial disposal wells (wells that take produced water from various operators for a fee) at least once per year.

There is no “schedule” for non-commercial disposal or injection well inspections. These wells are inspected based on several factors including their location (near sensitive environmental areas or public areas) and the operator’s compliance record.

In addition to inspections, each saltwater disposal well is required to be tested for mechanical integrity to show there are no leaks before the well begins to inject fluid. After this initial test, wells also must undergo mechanical integrity tests at least once every five years. The Railroad Commission’s standard mechanical integrity test (MIT) is designed to identify small leaks before they become catastrophic failures. Wells that fail MITs must be shut in immediately and repaired until they pass an MIT, or plugged within 60 to 90 days. Operators are required to notify the commission prior to conducting the test to allow the Commission’s staff the opportunity to witness the test. Commission inspectors randomly witness about one third of these tests to verify compliance. The commission often directs injection well operators to conduct an MIT to verify the mechanical integrity of a well when troubleshooting potential problems.

How many gallons of fluid are disposed in the wells?

You can use the online H-10 Annual Disposal/Injection Well Monitoring Report Query to obtain information on the amounts of fluid injected. Searches can be conducted by Commission district or county, operator number, lease or field. Be sure to use the reset button if you are performing more than one query.

Why isn’t this fluid being recycled instead of injected?

While some portion of hydraulic fracturing flow back fluid may be recycled or reused in subsequent hydraulic fracturing jobs, the majority of these fluids are disposed of by injection into geologically confined underground formations.

The primary reason cited by operators for injecting waste fluid is that it is less expensive than recycling. However, just as operators have used technology to bring about advances in oil production, they are also looking for technological advances to reduce fresh water use.

In March 2013, the Commission adopted new rules to encourage Texas operators to continue their efforts at conserving water used in the hydraulic fracturing process for oil and gas wells, even though hydraulic fracturing and total mining use accounts for less than 1 percent of statewide water use, with irrigation, municipalities and manufacturing making up state’s top three water consumers.

Major changes adopted to the Commission’s water recycling rules include eliminating the need for a Commission recycling permit if operators are recycling fluid on their own leases or transferring their fluids to another operator’s lease for recycling. The changes adopted by the Commission also clearly identify recycling permit application requirements and reflect existing standard field conditions for recycling permits.

The Commission hopes that by removing regulatory hurdles, these rule amendments will help foster recycling efforts by oil and gas operators who continue to examine ways to reduce freshwater use when hydraulically fracturing wells.

State Managed Well Plugging

Although most oil and gas wells that are no longer productive are plugged by the responsible operators, the Railroad Commission of Texas administers a program to plug abandoned oil and gas wells.

Part 2


Income, costs, and profits from saltwater disposal (SWD) wells fit into a complex equation.

If the investor is careful, costs and net revenue can be remarkably stable, leading to steady profits and reliable forecasts. This current post will take an abbreviated look at typical costs, market trends, potential problems and due-diligence issues for the careful investor.

CAPEX: Capital costs for disposal well projects can be listed in several categories:

Well costs – whether drilling and completing a new well or purchase of an existing bore-hole – these costs can be very easily be into the millions. At least one well is needed but a back-up well is essential to provide constant service at a large disposal facility.

Surface equipment – these items might range from several steel or fiberglass tanks, transfer and injection pumps, to extensive concrete pad and full electronic tracking systems.

SWD operator may elect to use his own transport trucks to pick up and deliver water.

Pipelines – long-term customers will want to be serviced by underground pipelines to avoid problems and cut costs; these might be installed by the customer or by the disposal well operator.

Water treatment facilities – might include filters, oil separators, polymer breakers, and paraffin blocks. Generally treatment is meant to improve injection efficiency prolong the life of the tubulars.

OPEX: Operation and Maintenance costs will of course be on-going throughout the life of the project.

Power consumption by the facility for pumps, lights, and secondary equipment.

Personnel costs can be large if 24-hour operation is adopted, if trucks are used, or if water treatment must be extensive. Heavy equipment must be used by staff but operations are not routinely hazardous.

Motor fuel, lubricants, and chemical costs can be significant.

SWD well and equipment maintenance will be significant over the life of the well; working over the well to repair bad casing or a bad packer can cost a half-million dollars.

Regulatory compliance will vary between agencies but monthly and annual reports and tests are usually required. An annual mechanical integrity test of the well will require that the well is shut-in for the day with resultant loss in revenue.

Environmental liabilities are unlikely but real, tanks are protected by fire-walls but wellheads are usually not and they can have leaks. Trucks can suffer leaks while loading or unloading. Pipelines can leak at the surface or below the surface. Insurance and rapid-response need to be arranged before operation starts.

Revenues: Several profit streams may be present at the disposal facility:

  1. Disposal of produced water is of course the principal source of revenue for the well; revenue will depend upon the amount of production in the area, the average water cut (percentage of water in the production stream), and the other disposal wells in the area.
  2. Captured crude oil is also an important economic factor. The amount of entrained oil in the water will vary by region and by formation but is often close to 1% of the produced water volume. Revenue is important since the sale of this recovered oil is without royalties
  3. Storing and selling heavy brine can be a source of profits if local operators use heavy brine for drilling or completing wells.
  4. Some produced water can be easily treated for a specific re-use such as drilling or fracking.

Trucking: Saltwater hauling can readily be incorporated into the SWD project as a way to increase traffic to the SWD and an added profit stream. A fleet of tank trucks in several sizes can be purchased to insure access to most well site locations. Trucks and trailers are expensive, require frequent maintenance to continue to be efficient, require an adequate truck shed and yard but CAPEX and OPEX for the trucking equipment can be recouped through trucking charges to the area’s oilwell operators. Indeed, if his competitors choose to use trucks, our SWD operator will very likely be forced to add trucking to his repertoire in order to maintain customers.

Landfilling: New drilling wells and older producing wells spin-off liquid wastes that are best injected into an SWD, but they also produce copious volumes of solid wastes that cannot be injected. For example, drill-cuttings are generated while drilling a well; these cuttings are high in salinity and high in oil & grease content. Cuttings are coarse and cannot be liquefied; they are not to be injected into an SWD well except under very unusual conditions. Cuttings and other solids such as contaminated soil are best landfilled and this can be done on-site into a small, lined trench or at a large commercial facility.

An oil & gas landfill can be merged with an SWD facility when there is sufficient acreage available and sufficient working capital can be arranged. Regulators usually require that a commercial landfill be equipped with an appropriate geo-membrane liner to isolate the fill contents from groundwater and surface water runoff. The incorporation of a solid waste landfill with the SWD will allow the project owners to accept and bill for all the wastes generated by E&P facilities.

Market Trends: Any business must seek to match its facilities to the demands of the market – if the restaurant is over-built to the clientele, efficiency and net revenues suffer. At the same time the businessman must be knowledgeable of market trends – are demands growing every year or are they shrinking?

If a new SWD project has high CAPEX demands it will likely require several years to pay-out and accurate knowledge of the local produced water trends is vital.

Following are aspects that need to be considered to understand the local market (note that the word “local” will vary from project to project, its radius is determined by the distance commonly traveled by water trucks in the area):

– Number of producing wells making water in the area. This count can be made from government records, either by county or by an easily-defined polygon. Active and shut-in wells are usually listed so that tabulations can be made.

– Change in the number of producing wells in the past 10 or 20 years. Depending upon the agency, monthly or annual totals can be retrieved and plotted in a simple graph to identify changes and current trends.

– Number of new wells drilled this year. New wells will involve large volumes of drilling waste needing to be managed. Older wells will show increases in the amount of water produced every day.

– Number of SWDs in the area and the changes in the past 10 or 20 years.

All of these trends have their own causes and implications for the current and future SWD market. The SWDI specializes in the interpretation of market trends and can help investors.

Potential Problems: There are issues that can exist in area or that can happen in the future that will have a significant effect on the economics of the SWD project:

Inadequate injection zone. The injection zone is one of the most important aspects of the SWD; it needs capability (the ability to take fluid at a given pressure, as measured by permeability) and capacity (the ability to store fluid over a long period as defined by porosity). Without both properties, the SWD may not be a suitable candidate. If the well exists and has a history of injection, certain forecasts can be attempted but if the well has not yet been drilled, the forecast will need to be extrapolated from nearby wells.

Scale and fouling in the well. Some injection zones are sensitive to certain saltwater chemistry, their permeability can be fouled with precipitating scale; this must be removed by periodic flushing with acid. At other times customers can submit waste water that contains drilling mud or cement, fluids that can permanently damage the injection zone. The SWD might need to be re-perforated or re-drilled.

Seismic activity can of course happen anywhere in the United States on any day of the year but an earthquake near an SWD has a certain implication for the news media and people who are exposed to that media. This subject has been dealt with in other blog-posts so details are not needed here. It appears to be true that some SWDs cause some earthquakes in some areas of the country. If a string of quakes is linked to an SWD, the operator may wish to perforate a different zone, cut the rate of injection, or drill a new well at another location.

Impact to nearby water well can have a myriad of causes but an SWD is a common target. Analyses of the impacted well and surrounding water wells are a must in order to identify the contaminants. The contaminants can then be related back to the impacting source which might be percolating fertilizer run-off or oilfield brine. After the point-source of the contamination is traced down, the SWD operator might want to drill a new private water well or another solution.

Loss of mechanical integrity within the SWD well implies corrosion or crack in the casing, a hole in the injection tubing, or leak in the packer. In any case it must be repaired before injection can resume. Repairs can shut-in the well for weeks waiting on repairs.

Due-Diligence Considerations: Prior to investment or purchase, the investor would do well to consider a number of factors involved in the subject SWD project:

  1. Market analysis to determine current market status and future market.
  2. New drilling plays in the general area.
  3. Condition of current SWDs in the area.
  4. Newly permitted SWDs in the area.
  5. Appropriateness of the selected site:
  6. Easy road access.
  7. Adequate surface area for planned facilities.
  8. Separation from residences.
  9. Dates and locations of any previous spills or leaks.
  10.   10.Capability of the injection zone in the area.
  11. 11.Regional subsurface problems such as faults and corrosive groundwater.
  12. Investors considering a SWD project must investigate the’ pros and cons of the specific project whether it is in operation or is meant to be drilled and the surface facilities built from scratch.  An experienced, full-service contractor such as RMS Technology can help  evaluate the project.