Eagle Ford Sale FAQ
Fequently Asked Questions about The Texas Eagle Ford Shale Formation from Domestic Drilling and Operating
Domestic Drilling and Operating has established itself as a leader in Texas energy operations in the Eagle Ford Shale through unwavering commitment to comprehensive expertise and operational excellence. Here are some common questions about the Eagle Ford Shale. Our team leverages decades of hands-on experience across Texas’s most significant oil and gas formations—from traditional South Texas conventional plays to the revolutionary unconventional shale formations that continue to reshape the energy landscape.
Our deep expertise extends to emerging opportunities in overlooked basins and includes extensive operations in the highly productive Eagle Ford shale. The wealth of natural oil and gas resources in the Eagle Ford Shale represents more than just geological potential—it reflects Drilling & Operating’s practical experience built through successful drilling programs, consistent production results, and strategic investments throughout Texas’s premier energy-producing regions, with particular strength in the Eagle Ford and other critical shale oil formations. Here are our commonly asked questions about the Eagle Ford Shale
What are the sizes of the proration units for the Eagle Ford Shale Fields?
Proration units currently range from 40 to 640 acres, with individual field rules for each Eagle Ford Shale Field requiring careful review and consideration.
Explain why a surface location for horizontal wells is not required to be located on the lease that is being drilled?
Operators frequently employ horizontal and deviated drilling from remote surface locations to reach productive geological formations underlying areas where direct surface access is unavailable or undesirable—including municipal parks, waterways, and residential neighborhoods. This approach enables companies to acquire surface rights from nearby, accessible locations while still accessing valuable subsurface resources.
Explain why a surface location for horizontal wells can be located on a lease closer to a lease line than the field rules require?
Horizontal well field rules focus specifically on regulating the “horizontal drainhole”—defined under Rule 86 as the wellbore section drilled within the correlative interval from penetration point to terminus. This regulatory framework allows surface locations to be positioned anywhere on the lease, as these locations are not considered part of the horizontal drainhole within the production-bearing correlative interval.
What are the plastic lining requirements for drilling pits and frac water pits?
The Railroad Commission requires operators to implement pollution prevention measures for both surface and subsurface water protection, though specific plastic liner requirements for drilling pits and frac water pits are not mandated at the state level. In areas with permeable soil conditions, many operators choose to install protective liners as a best practice, while some local jurisdictions may enforce mandatory lined pit requirements.
What is the requirement for reporting production for a well after it has been completed and how do I find out what has been reported?
Railroad Commission rules require operators to file well completion forms with the Commission within 30 days after well completion or 90 days after completing drilling operations, whichever occurs first (16 TAC §3.16). Monthly production reporting must begin the month following initial well production. Production information is accessible through the RRC website using the Production Data Query (PDQ) application or by visiting the RRC Online Research Queries portal.
How long does the RRC allow an operator to flare gas from a new well completion until the gas is then connected to the pipeline?
Railroad Commission regulations generally allow gas to be released for a period not to exceed ten (10) producing days after initial completion, recompletion in another field, or workover operations in the same field. However, the Commission may grant exceptions to this rule under certain circumstances. See 16 TAC §3.32 (Statewide Rule 32).
What is the typical size, shape and restoration of a drilling location in the Eagle Ford?
There are no standard location shapes or sizes; each rig has its own individual “footprint.” Texas law allows an operator the right to use as much of the surface as necessary to explore, drill and produce the minerals from a property. Leases or ordinances may limit the amount of surface that an operator may use and dictate restoration of the site.
What is law regarding ingress and egress using existing roads?
An operator has the right of ingress and egress to the property for the purpose of exploring, drilling and producing the minerals. This right cannot be denied under Texas law, as the mineral estate is dominant over the surface estate, but it does not require surface owners to allow operators to use existing roads. Should disagreements occur, it is a civil issue that must be pursued through the court system.
What can be done about the stormwater runoff?
The Commission’s regulations ensure the quality of waters (and land) that could be potentially impacted by oil and gas operator activities. The Commission’s current rules define “pollution of surface or subsurface water” broadly: “The alteration of the physical, thermal, chemical, or biological quality of, or the contamination of, any surface or subsurface water in the state that renders the water harmful, detrimental, or injurious to humans, animal life, vegetation, or property, or to public health, safety, or welfare, or impairs the usefulness or the public enjoyment of the water for any lawful or reasonable purpose.” Please see 16 TAC §3.8.
How will all this activity affect our property values?
When will they close the pit?
What is the process a drilling company must go through to receive a drilling permit from the RRC?
To obtain a drilling permit from the RRC, an operator must have on file an active P-5 Organization Report in accordance with Statewide Rule 1 (16 TAC §3.1) (SWR 1-Organization Report; Retention of Records; Notice Requirements), which identifies the operator and its officers.
(Note: all RRC Rules are available on the Commission’s web page at https://texas-sos.appianportalsgov.com/rules-and-meetings?interface=VIEW_TAC&part=1&title=16.)
The operator also must have the proper amount of financial assurance on file. The operator must submit a site-specific Form W-1 (application to drill) with a plat to scale showing the requirements listed in Statewide Rule 5 (16 TAC §3.5) Application To Drill, Deepen, Reenter, or Plug Back.
They must submit a Form P-12 (certificate of pooling authority), a plat identifying offset operators, a service list for notice, and any waivers where applicable. Permit Application Fees must be paid based on depth, exceptions and whether or not processing a permit application is expedited. There also are Financial Security Requirements (Statewide Rule 78 (16 TAC §3.78) Fees and Financial Security Requirements)
Do they have to show there is likely to be oil or gas in that area?
Is an oil or gas operator required to perform an environmental study or something similar?
What factors are considered in reviewing a drilling permit application, and who specifically approves this application (district office supervisor? commissioners?)
- Survey name and distances from lease lines and between wells.
- Lease name, well number and operator name
- Distances to nearest well, acreage and lease distances (relating to the field rules)
- Check for exceptions to rules 16 TAC §3.37 (Statewide Spacing Rule), §3.38 (Well Densities), §3.39 (Proration and Drilling Units: Contiguity of Acreage and Exception Thereto), §3.40 (Assignment of Acreage to Pooled Development and Proration Units).
How often are wells inspected?
What types of things do inspectors look for?
Can the RRC assist with mineral lease agreements?
With respect to entry into lease agreements and actions of individuals, please be advised that the Railroad Commission’s jurisdiction is limited to issues concerning the permitting and production from oil and gas wells in the State of Texas. The Commission has no jurisdiction over property interests or contractual rights, including issues regarding the validity of existing oil, gas and mineral leases and the conduct of individuals attempting to obtain leases. If you have a question concerning the validity of an existing lease or the actions taken by individuals in an attempt to secure the rights to develop the minerals within a particular area, you may wish to consult an attorney with expertise in oil and gas law.
The Commission does maintain records regarding the reported production and disposition of all oil and gas produced from wells in the State. This information may be helpful in determining your interests and any development in the area surrounding your property. Additionally, the Commission also maintains records regarding the permitting of wells. These records include plats and other documents designating the acreage in a pooled unit. These records are required to obtain a drilling permit and for production after a well is completed.
If you have the RRC Identification Number for a well (either a five digit number for oil wells or a six digit number for gas wells) you can obtain all reported production information from January 1993 to present and can obtain access to the permitting records at the Commission’s website https://www.rrc.texas.gov. For production information, please use the Commission’s Production Data Query application to get access to the on-line database for these records. For drilling permit information, please use the Commission’s Drilling Permit application to get access to the on-line database for these records.
I have heard about radiation issues associated with oil and gas activities. What are the issues and risks?
Subsurface formations may contain low levels of radioactive materials such as uranium and thorium and their daughter products, radium 226 and radium 228. These materials, called Naturally Occurring Radioactive Materials or NORM, can be brought to the surface in the formation water that is produced in conjunction with oil and gas operations. NORM in these produced waters typically consists of the radionuclides, radium 226 and 228. In addition, radon gas, a radium daughter, may be found in produced natural gas. Because the levels typically are so low, the NORM in produced waters and natural gas is not a problem in Texas unless it becomes concentrated in some manner.
Through temperature and pressure changes that occur in the course of oil and gas production operations, radium 226 and 228 found in produced waters may co-precipitate with barium sulfate scale in well tubulars and surface equipment. Concentrations of radium 226 and 228 may also occur in sludge that accumulates in oilfield pits and tanks. These solids become sources of oil and gas NORM waste. In gas processing activities, NORM generally occurs as radon gas in the natural gas stream. Radon decays to Lead-210, then to Bismuth-210, Polonium-210, and finally to stable Lead-206. Radon decay elements occur as a film on the inner surface of inlet lines, treating units, pumps, and valves principally associated with propylene, ethane, and propane processing streams. The highest risk of exposure to oil and gas NORM is to workers employed to cut and ream oilfield pipe, remove solids from tanks and pits, and refurbish gas processing equipment.
Regulatory programs for NORM are administered by both the Texas Department of State Health Services (DSHS) and the Railroad Commission (RRC). The DSHS regulates all activities, except disposal, involving management of NORM and NORM containing or contaminated materials under 25 Texas Administrative Code §289.259. This includes jurisdiction over possession, use, transfer, transport, recycling, decontamination of equipment and facilities and/or storage of oil and gas NORM wastes, other than such activities when they occur at the site (e.g., lease, unit, or facility) where disposal of oil and gas NORM waste will occur.
The DSHS’s radiological program protects the occupationally exposed as well as the public from unnecessary exposure to radiation. The DSHS regulations establish protection standards and requirements for management of NORM, other than disposal. The rules include exemption criteria for certain NORM containing or contaminated materials. Anyone managing NORM materials above the exemption levels must comply with certain standards.
The RRC has jurisdiction over disposal of oil and gas NORM waste and the management of NORM waste at an oil and gas property to facilitate disposal at the site under 16 Texas Administrative Code, Chapter 4, Subchapter F. The RRC’s rules were developed in consultation with the DSHS regarding protection of public health and the environment. The relation of exposure pathways and the health risks relative to those pathways was DSHS’s basis for adopting the regulatory exemption levels. Likewise, the adoption of oil and gas NORM waste disposal options is a result of evaluation of the risk relative to each disposal method. osure pathways and the health risks relative to those pathways was DSHS’s basis for adopting the regulatory exemption levels. Likewise, the adoption of oil and gas NORM waste disposal options is a result of evaluation of the risk relative to each disposal method.
Each agency is responsible for enforcing its own rules; however agencies do communicate with each other on particular sites or issues as necessary through the Memorandum of Understanding between DSHS and RRC and participate (along with the Texas Commission on Environmental Quality) in quarterly Texas Radiation Advisory Board (TRAB) meetings. The Texas Radiation Advisory Board serves as the state’s advisor on all radiation issues and reviews policies, programs, and proposed rules for agencies that regulate radiation.
For specific regulatory questions, operators should consult directly with DSHS for NORM licensing and management issues or RRC for NORM disposal matters.
