APPENDIX 9

APPENDIX 9

OIL AND GAS OPERATIONS

GEOPHYSICAL EXPLORATION 

Oil and gas can be discovered by either direct or indirect 

exploration methods such as the mapping of rock outcrops, 

seeps, borehole data, and remote sensing data. In many cases 

indirect methods, such as seismic, gravity, and magnetic 

surveys are required to delineate subsurface features which 

may contain oil and gas. 

Gravity Surveys 

Gravitational prospecting detects micro-variations in gravitational attraction caused by the differences in the density of 

various types of rock. Gravity data is used to generate 

anomaly maps from which faults and general structural trends 

can be interpreted. These surveys are generally not considered definitive due to the many data corrections required (e.g., 

terrain, elevation, latitude, etc.) and the poor resolution of 

complex subsurface structures. The instrument used for 

gravity surveys is a small portable device called a gravimeter. 

Generally measurements are taken at many points along a 

linear transect and the gravimeter is transported either by 

backpack, helicopter, or off-road vehicle. The only surface 

disturbance associated with gravity prospecting is that caused 

by a vehicle, if used. 

Geomagnetic Surveys 

Magnetic surveys use an instrument called a magnetometer to detect small magnetic anomalies caused by mineral and 

lithologic variations in the earth’s crust. These surveys can 

detect large trends in basement rock and the approximate 

depth to those basement rocks, but in general they provide 

little specific data to aid in petroleum exploration. Many data 

corrections are required to obtain reliable information and 

maps generated lack resolution and are considered preliminary. Magnetometers vary greatly in size and complexity and 

in general most magnetic surveys are conducted from the air 

by suspending a magnetometer under an airplane. Magnetic 

surveys conducted on the ground are nearly identical to 

gravity surveys and surface disturbance is minimal to nonexistent. 

Seismic Reflection Surveys 

Seismic prospecting is the best and most popular indirect 

method currently utilized for locating subsurface structures or 

stratigraphic variations which may contain oil and/or gas. 

Seismic energy (shock waves) is induced into the earth using 

one of several methods. As these waves travel downward and 

outward they encounter various rock strata, each having a 

different seismic velocity. As the wave energy encounters the 

interface between rock layers, some of the seismic energy is 

reflected upward. Sensing devices commonly called geophones are placed on the surface to detect these reflections. 

The geophones are connected to a data recording truck which 

stores data on magnetic tape. The time required for the shock 

waves to travel from the shot point down to a given reflector 

and back to the geophone can be related to depth. 

There are many methods available today which an 

explorationist can use to induce the initial seismic energy into 

the earth. All methods require preliminary surveying and 

laying of geophones. The thumper and vibrator methods 

pound or vibrate the earth to create a shock wave. Usually four 

large trucks (buggies) are used, each equipped with vibrator 

pads (about four-foot square). The pads are lowered to the 

ground and vibrators on all trucks are triggered electronically 

from the recording truck. Information is recorded and then the 

trucks move forward a short distance and the process is 

repeated. 

Vibrator buggies currently weigh up to 67,000 pounds and 

have tires up to 4 feet wide. They travel with less surface 

loading than a pickup truck. These buggies are spread out 

from point to point to eliminate leaving a trail. Surface 

vegetation, (including shrubs) is pushed down but not crushed 

and broken. A small portion of the shrubs are lost due to this 

action. Observation of a track a year later makes it hard to find 

where they traveled. Working during winter conditions with 

snow can cause even less surface damage. 

Shothole prospects use drill buggies on rough terrain and 

drill trucks on flatter landscape. Trucks cause more damage 

than buggies. A water truck or buggy may travel with the drill 

rig. The water is used to keep the hole open while drilling. 

Small-diameter holes are drilled to depths of 80 to 200 feet. 

Four to twelve holes are drilled per mile of line. Usually, a 20-

pound charge of explosives is placed in the hole, covered, and 

detonated to generate seismic shock waves. Helicopters may 

carry a portable drill into rugged terrain. Another portable 

technique is to carry charges in a helicopter and place them on 

wooden sticks, or lath, three feet or so above the ground. 

Charges used are either 2-1/2 or 5 pounds. Usually, ten 

charges in a line are detonated at once. Seismic lines are 

aligned relative to the regional structure to make interpretation more accurate. 

The geophones and energy source are located along lines 

on a one- to two-mile grid. Although alignment may be fairly 

critical, spacing of the lines can often be changed one-quarter 

mile on a one-mile grid before the results will significantly 

affect the investigation program. 

A typical drilling seismic operation may utilize 10 to 15 

men operating five to seven trucks. Under normal conditions, 

3 to 5 miles of line can be surveyed each day using the 

explosive method. The vehicles used for a drilling program 

include several heavy truck-mounted drill rigs, water trucks, 

a computer recording truck, and several light pickups for the 

surveyors, shot hole crew, geophone crew, permit man, and 

party chief. 

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Public roads and existing private roads and trails are used. 

Off-road cross-country travel may be necessary to carry out 

tasks. Motor graders and/or dozers may be required to provide 

access to remote areas. Concern about unnecessary surface 

disturbance has caused government and industry to more 

carefully plan surveys. As a result, earth moving equipment 

is now only rarely used in seismic exploration work. Several 

trips a day are made along a seismograph line; this usually 

establishes a well defined two-track trail. The repeated 

movement back and forth along the line (particularly the light 

pickups) defines the trail. Spreading vehicles out so that 

vehicle routes are not straight, and vehicles do not retrace the 

same route has in some cases prevented the establishment of 

new trails, and has reduced impacts. 

A variation on the above techniques is the three dimensional seismic profile survey. This type of survey differs from 

the more common survey in the greater number of data points 

and the closer spacing of the lines. Three dimensional seismic 

surveys are more computer intensive, but result in a more 

detailed and informative subsurface picture (with an accompanying higher cost). The orientation and arrangement of 

three dimensional seismic surveys are less tolerant of adjustments to the physical locations of the lines and geophones, but 

they are also more compact in areal extent. 

Each of the foregoing methods have inherent strengths and 

weaknesses and explorationists must decide which method is 

the most practical with regard to surface constraints (such as 

topography) but will still produce information which can be 

useful for the particular study. Extensive computer processing of the raw data is required to produce a useable seismic 

section from which geophysicists may interpret structural 

relationships to depths of 30,000 feet or more. The effective 

depth of investigation and resolution are determined to some 

degree by which method is used. 

Geophysical Management (Permitting 

Process) 

Geophysical operations are reviewed by the federal surface management agency - BLM, Bureau of Reclamation, or 

Forest Service, as appropriate. Good administration and 

surface protection on geophysical operations can only be 

accomplished through close cooperation of the operator and 

affected agency. The responsibilities of the geophysical 

operator and the Field Manager are as follows (USDI 1989b): 

1. Geophysical Operator - An operator is required to file 

with the Field Manager a “Notice of Intent to Conduct Oil 

and Gas Exploration Operations.” The “Notice of Intent” 

shall include a map showing the location of the line, all 

access routes, and ancillary facilities. The operator must 

be bonded and file evidence of bonding with the 

Notice.Any surface disturbance may require a cultural 

resources survey and a pre-work field conference. Earthmoving equipment will only be used with prior approval. 

Upon completion of operations and rehabilitation, the 

operator must file a “Notice of Completion of Oil and Gas 

Exploration Operations”. 

2. Field Manager - The Field Manager shall apprize the 

operator of the practices and procedures to be followed 

prior to commencing operations on BLM-administered 

lands. The Field Manager will consent to bond release 

once the terms and conditions of the Notice have been 

met. 

State Standards 

In Wyoming, the operator is required to register with the 

State. State standards for plugging shot holes, personnel 

safety, etc., will be followed. 

Mitigation 

Seasonal restrictions may be imposed to reduce conflicts 

with wildlife, watershed damage, and hunting activity. Compliance inspections during the operation ensure that stipulations are being followed. Compliance inspections upon 

completion of work ensure that the lines are clean and the drill 

holes are properly plugged. 

OIL AND GAS LEASING 

The Mineral Leasing Act provides that all public lands are 

open to oil and gas leasing unless a specific order has been 

issued to close an area. Based on the Federal Onshore Oil and 

Gas Leasing Reform Act of 1987, all leases must be exposed 

to competitive interest. Leases are issued for a term of 10 

years, or as long as production continues. 

The Federal Government receives yearly rental fees on 

non-producing leases. Royalty on production is received on 

producing leases, one half of which is returned to the State of 

Wyoming. 

DRILLING PERMIT PROCESS 

A federal lessee or operator is governed by procedures set 

forth by Onshore Oil and Gas Order No. 1, “Approval of 

Operations on Onshore Federal and Indian Oil and Gas 

Leases,” issued under 43 CFR 3164. Operating Order No. 1 

lists the following as pertinent points to be followed by the 

lessee or operator: notice of staking; application for permit to 

drill (APD), which includes a multi-point surface use and 

operations plan; approval of subsequent operations; well 

abandonment; water well conversion; responsibilities on privately owned surface; and reports and activities required after 

well completion. 

The federal lessee or operating company selects the location of a proposed drill site. The selection of the site is based 

on spacing requirements, subsurface geology as interpreted 

by geologists and geophysicists, topography, and availability 

of funds for a specific well. Spacing requirements are established by the Wyoming State Oil and Gas Conservation 

Commission. Each well is to be drilled within a given distance 

from the center of a legal subdivision. A proposed location 

may be moved with a spacing exception granted by the Oil and 

Gas Conservation Commission. Occasionally, the Bureau 

may request that a lessee drill a well on the lease if it is 

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determined that federally owned minerals are being drained 

by an adjacent well on private or state owned minerals (USDI 

1981a). 

1. Notice of Staking - After the company makes the decision to drill, they must decide whether to submit a notice 

or APD. The notice consists of an outline of what the 

company intends to do including a location map and 

sketched site plan. The notice is then used as a document 

to review any conflicts with known critical resource 

values, and at the on-site inspection to provide the preliminary data to assess what additional items are necessary to complete the APD. 

2. Application for Permit to Drill (APD) - Regardless of 

whether an NOS is filed, the lessee or operator shall file 

an APD. No surface activity in conjuction with drilling 

is allowed until the APD is approved. A field inspection 

is held with the operator and any other interested party. 

The pre-site field inspection is used to evaluate the 

operator’s plan, assess the situation for possible impacts 

(surface and subsurface), and formulate resource protection stipulations. To lessen environmental impacts, a site 

may be moved, reoriented, or redimensioned, within 

certain limits. The proposed access road may also be 

rerouted (USDI 1981a). 

If necessary, site-specific mitigations are added to the APD 

for protection of surface and/or subsurface resource values in 

the vicinity of the proposed well. The Bureau is responsible 

for preparing environmental documentation necessary to satisfy the NEPA requirements and provide any mitigation 

measures needed to protect the affected resource values. 

Consideration is given to the protection of ground water 

resources. The geologist is required to identify the maximum 

depth of usable water as defined in Onshore Oil and Gas Order 

No. 2. Usable water is defined as that water containing 10,000 

parts per million or less of total dissolved solids. Determining 

the depth to fresh water requires specific water quality data in 

the proposed well vicinity or geophysical log determination of 

water quality, depending on existing well proximity and log 

availability. Water of this quality is to be protected, usually by 

surface casing and cement. 

Once approved, the operator has one year to commence 

construction and drilling operations. If construction does not 

begin within one year, the stipulations must be reviewed prior 

to approving another APD (USDI 1981a). 

Surface Disturbance Associated With 

Exploratory Drilling 

Upon receiving approval to drill the proposed well, the 

operator moves construction equipment over existing roads to 

the point where the access road will begin. Generally, the 

types of equipment include dozers (track-mounted and rubber-tired), scrapers, and motor-graders. Moving equipment to 

the construction site requires moving several loads (some 

overweight and overwidth) over public and private roads. 

Existing roads and trails are improved in places and occasionally culverts and cattleguards are installed if required. 

The length of the access road varies. Generally the shortest 

feasible route is selected to reduce the haul distance and 

construction costs. Environmental factors or the landowner’s 

wishes may dictate a longer route. In rough terrain, the type 

of construction is sidecasting (using the material taken from 

the cut portion of the road to construct the fill portion); slightly 

less than one-half of the road bed is on a cut area and the rest 

is on a fill area. Roads are usually constructed with a 14-foot 

(single lane) or 24-foot (double lane) running surface (in 

relatively level terrain). Soil texture, steepness of the topography, and moisture conditions may dictate surfacing the 

access road in some places but generally not for the entire 

length. 

Well locations are constructed differently, but in every 

case, all soil material suitable for plant growth is first removed 

from areas to be disturbed and stockpiled in a designated area. 

Sites on flat terrain usually require little more than removing 

the topsoil material and vegetation. Drilling sites on ridge tops 

and hillsides are constructed by cutting and filling portions of 

the location. It is important to confine extra cut material in 

stockpile rather than cast it down hillsides and drainages 

where it cannot be recovered for rehabilitation. 

The level surface needed to assemble and operate a drilling 

rig varies, but averages 300 by 350 feet. Figure 14 illustrates 

a typical well location layout. At least 25 feet of cut surface 

between the drill hole and edge of the drilling platform is 

normally needed. This ensures that the foundation of the 

drilling derrick is on solid ground and prevents it from leaning 

or toppling due to settling of uncompacted soil. In addition to 

the drilling platform, an 8- to 12-foot deep reserve pit is 

usually constructed. Generally, the reserve pit is 8 to 12 feet 

deep, but may be deeper to compensate for smaller length and 

width or deeper drilling depths. Depending on the relation of 

the location to natural drainages, it may be necessary to 

construct water bars or diversions. 

Moving a drilling rig requires moving 10 to 25 truck loads 

(some over legal weight and height) of equipment over public 

highways and private roads. The derrick when erected is 

approximately 160 feet high. 

Water for drilling is hauled to the rig storage tanks or 

transported by surface pipeline. Water sources are usually 

rivers, wells, or reservoirs. Occasionally, water supply wells 

are drilled on or close to the site. The operator must obtain a 

permit from the Wyoming State Engineer for the use of 

surface or subsurface water for drilling. When the Bureau 

holds the water permits for surface water (stock ponds), we 

must also approve such use. When drilling commences, and 

as long as it progresses, water is continually transported to the 

rig location. Approximately 40,000 barrels or 1,680,000 

gallons of water are required to drill an oil or gas well to the 

depth of 9,000 feet. 

Issuance of Rights-of-Way 

BLM rights-of-way are required for all facilities, tank 

batteries, pipelines, truck depots, powerlines, and access 

roads that occupy federally owned land outside the lease or 

unit boundary. When a third party constructs a facility or 

installation on or off the lease, a right-of-way is also required. 

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DRILLING OPERATIONS 

Rotary Drilling 

Starting to drill is called “spudding in” the well. Initially, 

drilling usually proceeds rapidly mainly due to the incompetent nature of shallow formations. While drilling, the rig 

derrick and associated hoisting equipment bear a great majority of the drill string’s weight (Figure 15). The rotary motion 

is created by a square or hexagonal rod, called a kelly, which 

fits through a square or hexagonal hole in a large turntable, 

called a rotary table. The weight on the bit itself is generally 

a small fraction of the total drill string weight. 

Drilling mud is circulated through the drill pipe to the 

bottom of the hole, through the bit, up the bore of the well, 

through a screen which separates the rock chips, and into 

holding tanks from which it is pumped back into the well. The 

mud is maintained at a specific weight and thickness to cool 

the bit, reduce the drag of the drill pipe on the sides of the well 

hole, seal off any porous zones, contain formation fluids to 

prevent a blowout or loss of drilling fluid, and bring the rock 

chips to the surface for disposal. Various additives are used 

in maintaining the drill mud at the appropriate viscosity and 

weight. Some of the additives are caustic, toxic, or acidic, but 

these hazardous additives are used in relatively small amounts 

during drilling operations. 

Eventually, the bit becomes worn and must be replaced. To 

change bits, the entire string of drill pipe must be pulled from 

the hole, in sections usually about 90 feet long, until the bit is 

out. The bit is replaced and then the drill string is reassembled 

and lowered into the hole, section by section, and drilling is 

started again. The process of removing and reinserting the 

drilling string uses much of the time required in drilling. 

Drilling operations are continuous, 24 hours a day and 7 

days a week. The crews usually work three 8-hour shifts or 

two 12-hour shifts a day. Pickups or cars are used for workers’ 

transportation to and from the sight. 

Upon completion of the drilling, the equipment is removed 

to another location. If oil or gas is not discovered in commercial quantities, the well is considered dry. The operator is then 

required to follow state and BLM policy procedures for 

plugging a dry hole. The drill site and access road are 

rehabilitated in accordance with the stipulations attached to 

the APD (USDI 1981a). 

Casing 

Various types of casing (steel pipe) are “screwed” together 

and placed in the drill hole to keep it open. It is cemented in 

place to protect against fluid movement between the casing 

and walls of the hole and to keep rocks and the well bore from 

pushing against the casing and damaging it. 

Surface casing which is properly set and cemented also 

protects surface aquifers from being contaminated by drilling 

and production operations. Surface casing should be set to a 

depth greater than the deepest fresh water aquifer which could 

reasonably be developed. Fresh water may exist at great 

depths but these aquifers are not normally considered to be 

important fresh water sources. Surface casing is large enough 

to allow subsequent lengths of smaller casing to be set as the 

well is drilled deeper. Cement is placed to fill the entire void 

between the pipe and the walls of the hole. 

Production casing or liner is intended to provide a conduit 

for the production of oil and gas so that little or no product is 

lost in “up-hole zones.” Generally only the bottom few 

hundred feet of intermediate or production casing is cemented 

which often leaves several thousand feet of open hole behind 

some casing strings. Currently, the operator is only required 

to cement off “hydrocarbon bearing zones.” Cement is placed 

across these zones to seal them and to prevent contamination 

of any water bearing zones or other porous zones by hydrocarbons. 

DEVELOPMENT AND 

PRODUCTION 

Wells are completed and production equipment installed if 

it is determined that oil or gas is present in commercial 

quantities. Natural gas is the primary product produced. 

Completion calls for the installation of steel casing, which is 

cemented in, to provide stability and to protect specific 

underground zones. The casing is perforated into the zone 

containing the oil or gas. Valves and pressure regulators are 

then installed to control flow of the oil and gas to production 

facilities. 

Pipeline quality gas at the wellhead requires a minimum of 

processing equipment. As the quality of gas decreases with 

the increased presence of water, dissolved solids, or liquid 

hydrocarbons, the amount of processing equipment increases. 

Water or liquid hydrocarbons in the gas are removed before 

the gas is mixed with other gas, usually at the wellhead. If 

liquid hydrocarbons are present, storage facilities (tank batteries) are required for the liquids until they accumulate in 

sufficient quantities to be hauled out by large trucks. 

Wyoming law prohibits the flaring or venting of natural 

gas. Exceptions allowed by the Wyoming Oil and Gas 

Commission are: 1) during testing of a new well, or 2) when 

the amount of gas produced with the oil is so small that 

pipeline construction is not practical. Otherwise, if a well 

produces both oil and gas, provisions for shipping the gas must 

be made before oil production can continue. 

The production equipment (heater-treater, holding facility 

for production water (if any is present), and tank battery) are 

either placed on a portion of the location (on cut rather than 

fill) or located a short distance from the wellhead along the 

access road. Production facility colors are required to be from 

the standard color chart. The heater-treater and tanks are 

surrounded by earthen dikes to contain accidental spills. 

Either all the facilities may be fenced, or only the production 

water pit may be fenced (USDI 1981a). 

Oil and Gas Exploratory Units 

Surface use in an oil or gas field may be affected by 

unitization of the leaseholds. In areas of federally owned 

minerals, an exploratory unit can be formed before a wildcat 

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APPENDIX 9

exploratory well is drilled. The boundary of the unit is based 

on geologic data. The developers of the unit can enter into an 

agreement to develop and operate, without regard to separate 

lease ownerships. All owners share in any well’s production 

and costs are allocated according to agreed upon terms. 

Unitization reduces the surface use requirements because 

all wells are operated as though on a single lease. Duplication 

of field processing facilities is minimized, because development and operations are planned and conducted by a single 

operator. Often powerlines are distributed throughout the unit 

and diesel engines are converted to electric motors. Unitization may also involve wider spacing than usual, resulting in 

fewer wells. Access roads are usually shorter and better 

organized (USDI 1981a). 

It is the general intent of unitization to pool or unitize the 

interests in an entire structure or area in order to provide for 

adequate control of operations so that development and production can proceed in the most efficient and economical 

manner, and with minimized environmental impact. Accordingly, each proposal to unitize federally supervised leases 

must be evaluated upon its specific merits. The unit agreement provides for the exploration, development, and production by a single operator. In effect the unit functions as one 

very large lease. 

Early consolidation of exploration and development efforts through unitization eliminates the need to drill protective 

wells (drainage avoidance) within unit boundaries. In a field, 

each lessee must drill his own well to obtain production and 

avoid being drained by nearby wells. 

Field Development 

The most important factor in further development of an oil 

or gas field is the quantity of production. Other considerations 

are whether the field is on a lease basis or unitized, the 

probability of profitable production, the necessity to protect 

federal mineral acreage from drainage by off-lease drilling, 

and the degree to which limits of the field are known. 

When a discovery is made, a well spacing pattern must be 

established before additional development begins. Spacing is 

regulated by the Wyoming State Oil and Gas Conservation 

Commission. Well spacing for gas wells is generally at 160 

to 640 acres per well and 160 acres or less for coalbed 

methane. APD procedures for development of wells are the 

same as those for wildcat (exploration) wells. 

New field developments are analyzed in an environmental 

assessment or EIS after the second or third confirmation well 

is drilled. The operator should then have an idea of the extent 

of drilling and disturbance required to extract and produce the 

oil and gas. Many fields go through several development 

stages. A field may be considered fully developed and 

produce for several years; later, a deeper pay zone may be 

discovered that leads to the drilling of more wells. A new state 

of development can lead to changes in the infrastructure of the 

field which must be approved by the BLM. 

As the productive life of a field progresses, problems may 

arise such as: erosion; unvegetated areas; washing out of 

drainage crossings and roads; plugging of culverts, deterioration of cattleguards; accumulation of derelict equipment; 

construction of unnecessary roads; unauthorized off-road 

cross-country travel; and improperly placed or unrehabilitated 

pipelines. The Bureau prepares rehabilitation plans to correct 

these problems and to return the field surface area to its 

original productivity. Ongoing restoration allows total reclamation to be completed more quickly when a field is finally 

abandoned (USDI 1981a). 

Production 

Gas, oil, and water are being produced in the area. 

Gas Production: A typical gas well location would consist 

of a wellhead, methanol injection equipment (to keep production and surface lines from freezing), a separator (which 

separates gas, oil, and water), a dehydrator (uses heat and 

glycol or CaCl to extract any water remaining with the gas), 

and an orifice meter. An intermitter is sometimes used to 

either shut-in the well to build up pressure or to blow the well 

down if it is being loaded with fluid. If the gas well is 

producing some oil or condensate, oil tanks are used to store 

the oil and condensate until it is sold via truck or pipeline. 

Water Production: Associated water produced with the oil 

or gas is disposed by trucking the water to a Department of 

Environmental Quality authorized disposal pit, by placing the 

water in lined or unlined pits, or through subsurface injection. 

The quality of the water often dictates the appropriate disposal 

method. 

Production Problems: Weather extremes pose problems for 

producers by causing roads to become impassable, equipment 

to malfunction, and freeze-up of flowlines, separators, and 

tanks. 

Plugging and Abandonment of Wells 

The purpose of plugging and abandoning a well is to 

prevent fluid migration between zones, to protect minerals 

from damage, and to restore the surface area. Each well has 

to be handled individually due to a combination of factors, 

including geology, well design limitations, and specific rehabilitation concerns. Therefore, only minimum requirements 

can be established, then modified for the individual well. 

The first step in the plugging process is the filing of the 

Notice of Intent to Abandon. This will be reviewed by both the 

Surface Management Agency and this Field Office. The 

Notice must be filed and approved prior to plugging a well. 

The operators plan for plugging the hole is reviewed and must 

meet the minimum requirements for plugging a well bore as 

stated in Onshore Order No. 2. Verbal plugging instructions 

can be given for plugging current drilling operations, but a 

Notice must be filed after the work is completed. If usable 

fresh water was encountered while the well was being drilled, 

the Surface Management Agency will be allowed, if interested, to assume future responsibility for the well and the 

operator will be reimbursed for the attendant costs. 

661