The unconstrained baseline RFD for oil and gas in the Planning Area is based on a set of reasonable geologic, engineering, and economic assumptions about resource occurrence only, and past and present activity, without management constraints on future activities. An unconstrained RFD provides a basis for comparing alternatives. Constrained oil and gas projections typically are lower than those in the unconstrained baseline RFD because of management constraints on oil and gas activities in the alternatives.
It is important to note that the RFD is not a decision, and it neither establishes nor implies a “cap” on development. Surface disturbance associated with well counts likely will be reduced in the future as the result of improvements in drilling- and well-completion technologies and techniques. Thus, the BLM uses any discussion of well counts in the RFD only to form the basis for an analysis of levels of impact. In addition, because the RFD is a snapshot in time, it cannot capture how future advances in technology may make it possible to exploit certain oil and gas plays in the future that are currently not economical or commercially exploitable.
Chapter 3 includes a summary of unconstrained baseline projections for oil and gas drilling activity in the Planning Area. Appendix T includes detailed projections of well counts by alternative, which vary by the degree of management constraints. See the RFD for oil and gas for more specific information on baseline oil and gas development and drilling potential in the Planning Area (BLM 2009e).
Table 4–5 summarizes projected new-well counts for the alternatives and the baseline unconstrained projection (only standard lease stipulations would be required) (BLM 2009u). The projected new-well counts and estimated surface disturbance associated with wells described in this section are for the period 2008 through 2027. Appendix T includes well projections by type of oil and gas well by alternative.
Table 4.5. Bighorn Basin Planning Area Projected New-Well Counts by Alternative
| Alternative | Total Coalbed Natural Gas Wells | Total Conventional Oil and Gas Wells | Total Oil and Gas Wells | Percent of Total Wells on Federal Mineral Estate |
| Baseline Unconstrained Projection1 | 150 | 1,715 | 1,865 | 72.6 |
| Alternative A | 130 | 1,511 | 1,641 | 68.9 |
| Alternative B | 84 | 936 | 1,020 | 49.9 |
| Alternative C | 124 | 1,644 | 1,768 | 71.1 |
| Alternative D | 98 | 1,436 | 1,534 | 66.7 |
Source: BLM 2009u
1Only standard lease stipulations would be applied.
Methods and assumptions used in this impact analysis include the following:
Unless otherwise noted, areas that are open to oil and gas leasing will be open to geophysical exploration subject to appropriate mitigation developed through use of the mitigation guidelines described in Appendix H.
Unless otherwise noted, areas closed to oil and gas leasing will be closed to geophysical exploration.
The BLM can authorize, subject to appropriate mitigation developed through use of the mitigation guidelines described in Appendix H, geophysical exploration activities in VRM Class I and II areas because the operations are short-term activities.
The BLM does not guarantee access to mineral leases that it issues.
Analysis considers the baseline total unconstrained oil and gas development potential taken from the RFD for oil and gas as summarized in Chapter 3 and applies the alternative constraints from the other resource programs as described in Chapter 2. The RMP will not modify existing leases; as old leases expire and new ones are issued, new leases would be subject to relevant stipulations. However, site-specific COA can be applied to applications for permit to drill (APDs) on existing leases to avoid adverse impacts to resource values by development per 43 CFR 3101.1-2.
Reasonable mitigation measures could include modification to siting or design of facilities, timing of operations, and specification of interim and final reclamation requirements. These modifications might occur only through site-specific post-lease actions (e.g., APDs and ROWs) that are supported by onsite conditions and/or project-specific NEPA analysis. Any exceptions, modifications, or waivers to lease stipulations will only be authorized in accordance with applicable regulatory guidelines. Surface-disturbing and other disruptive activities could occur at existing authorized facilities.
Post-lease NSO COA will not be applied to the entire acreage of existing oil and gas leases, as development must be allowed consistent with lease rights and terms.
Areas open for oil and gas leasing subject to major constraints have greater adverse impacts on oil and gas leasing, exploration, and development compared to acres subject to either moderate constraints or standard stipulations. All areas identified as open in this analysis are subject to at least standard stipulations. In addition, some of these areas are subject to moderate and/or major constraints.
| Alternative | Constraint Type acres | ||
| Moderate | Major | Administratively Unavailable or Closed | |
| Alternative A | 1,789,634 | 1,399,490 | 154,861 |
| Alternative B | 451,948 | 1,320,277 | 2,296,279 |
| Alternative C | 2,175,814 | 221,536 | 147,760 |
| Alternative D | 3,540,775 | 117,968 | 291,294 |
Moderate constraints are any stipulations or COA which may restrict the timing or placement of oil and gas development, but would not otherwise restrict the overall development. Moderate constraints include all TLS, CSUs, areas where surface-disturbing activity is avoided, and VRM Class II areas.
Major constraints are any stipulations or COA which may restrict the timing or placement of oil and gas developments and may result in an operator dropping the development proposal. Major constraints include NSOs, areas of overlapping TLS that last more than 6 months, areas closed to surface-disturbing activity, areas where surface-disturbing activity is prohibited, and VRM Class I areas. Leaseholders have the right to explore, develop, and produce mineral resources from any valid, existing lease, even if the area containing the lease was proposed to be closed to future leasing.
Because of overlaps between management restrictions on oil and gas leasing (i.e., CSU, TLS, and NSO), individual restrictions associated with resources and special designations described in this section are not additive. As described in the Glossary , the BLM has factored these overlapping restrictions into the overall oil and gas constraints (major, moderate, open, administratively unavailable) for each alternative, where appropriate. For example, while a TLS restriction is generally considered a moderate constraint, overlapping TLS that restrict the use of an area for 6 months or more are considered a major constraint. In areas where overlapping management is the same and applies year-round (e.g., two overlapping NSOs), there is no additional or additive effect. Finally, where different types of restrictions overlap (e.g., an area managed as an NSO for cultural resources and administratively unavailable for wildlife values), the more restrictive management would apply. Maps 17, 18, 19, and 20 provide a visual representation of constraints by alternative.
Surface use restrictions, including TLS, NSO stipulations, and CSU stipulations, as well as unavailable for leasing designations, cannot be retroactively applied to valid, existing oil and gas leases or to valid, existing use authorizations (e.g., APD). Post-lease actions/authorizations (e.g., APDs, road/pipeline ROWs), however, could be encumbered by TLS and CSU restrictions on a case-by-case basis, as required through project-specific NEPA analysis or other environmental review.
Oil and gas resources are considered unrecoverable in areas designated unavailable for leasing. They would also be considered unrecoverable in areas open to leasing but where surface use constraints prohibit development operations on areas larger than can be technically and economically developed from offsite locations. Oil and gas resources within leased in-holdings would be considered recoverable.
Oil and gas development potential is based on the following categories:
High potential for hydrocarbon development indicates areas where the average well density is anticipated to be more than 100 wells per township.
Moderate potential for hydrocarbon development indicates areas where the average well density is anticipated to be between 20 and 100 wells per township.
Low potential for hydrocarbon development indicates areas where the average well density is anticipated to be 2 to fewer than 20 wells per township.
Very low potential for hydrocarbon development indicates areas where the average well density is anticipated to be fewer than 2 wells per township.
No potential for hydrocarbon development indicates areas where no wells are anticipated.
Directional drilling viability and offset distance varies with the target formation, the top depth of the target formation, and formation productivity. Directional drilling distances of ¼ mile are assumed to be standard practice in most formations with current technology.
For the purposes of this analysis, hydrocarbon resources more than ½ mile inside the boundary of an NSO area would generally be unrecoverable.
Directional drilling potentially increases well development costs by approximately 10 percent to 15 percent for offset distances of up to 2,000 feet (Eustes 2003).
Directional drilling can increase the risk of unrecoverable hydrocarbon resources in cases when the drill stem gets irretrievably stuck and the production casing cannot be set to the bottom of the production formation.