4.1.1 Overview of the Exploration–Production Life Cycle

Before oil or gas production starts, an unconventional geologic prospect in the Marcellus Formation or Bakken Formation was already developed by geologists and engineers supported by field activities: geophysical surveying, area‐wide leasing, drill pad construction and rig mobilization, well drilling, HVHF stimulation, and well completion. This chapter describes the activities and technologies involved with the exploration and production of specific unconventional petroleum resources: tight oil and shale gas.

A three‐dimensional (3D) visualization of the production well in the tight oil Bakken Formation in the Williston Basin in North Dakota (Figure 4.1) shows the horizontal well production and a significant depth of the reservoir about 9 000 ft (2 743 m) to 10 000+ ft (3 048+ m) from the surface. The timing of the entire exploration–production life cycle is estimated to be about 45 years for the Bakken Formation (Figure 4.2). This figure also shows the length of time required for the HVHF stimulation operations, which is about two weeks to two months. Compared with a potential oil production period of 45 years (540 months), the duration of the initial fracking operations is 0.37% of the total exploration–production life cycle. Even though oil production for the Bakken example (Figure 4.2) declines rapidly from an initial high of 904 barrels per day (bpd) to <50 bpd in about 48 months, the total oil production is projected to last for decades. As oil production declines, water production increases greatly.

4.1.2 Phases of Activity

The exploration–production life cycle (Table 4.1) consists of seven phases.

For unconventional resource exploration, the process starts with developing an overall geologic concept for the oil or gas prospect (Table 4.2).

Many unconventional oil and gas resources reside in basin‐wide, continuous petroleum accumulations within rock, which coexists as both source and reservoir. Pore throats for generally tight formations which are common to unconventional resources are estimated to be nanometer sized. For comparison, a clean, well‐sorted sandstone as might be found in a conventional reservoir (Magoon and Dow 1994) would have millimeter‐sized to micrometer‐sized pore throats (Zou et al. 2013). Permeabilities are measured in the porous portion of the rock. Shales and fine‐grained rocks have natural fractures and microfractures, and hydraulic fracture stimulation opens these fractures and initiates new interconnected fractures to allow petroleum hydrocarbons to drain from the horizontal wells.

The smaller pore size in the coexisting source and reservoir rock of the unconventional oil and gas prospect will not allow petroleum to naturally flow from these rocks without advanced drilling and complex extraction methods. Horizontal wells and large‐scale hydraulic fracturing are needed to develop unconventional petroleum deposits. The hydraulic fracturing creates or enhances existing fractures, providing connected flow pathways in the rocks combined using water under high pressure, with a minute amount of specialized chemicals and fine‐grained proppants.

Hydraulic fracture stimulation is required for low‐permeability to extremely tight rocks (Figure 4.3) with a permeability of <1 millidarcy (mD) or ~1 μm². Some conventional reservoirs with larger permeability values can optimize production using horizontal well technology to increase the net reservoir thickness and the hydraulic fracture stimulation to reduce formation damage and increase hydrocarbon flow into the well.

4.2.1 Unconventional Resource Prospecting

In the past, tight, organic‐rich shale deposits were viewed as potential source rocks for conventional hydrocarbon reservoirs. Now these same formations are being seen for their huge potential for in situ oil and gas production. The natural permeability of shales is on the order of a few hundred nano‐darcies (0.0001 md) to a few millidarcies (0.001 md), and the efficient recovery of the oil held in the shale matrix requires long horizontal wells to drain the hydrocarbons and intensive well stimulation completion techniques using hydraulic fracturing and specialized chemicals to recover the oil and gas.

The economics of an oil or gas prospect relates to the volume of recoverable hydrocarbons that are present, the costs of extraction, and the associated economics of conveying the extracted oil and gas to customers. For the unconventional prospect, the volume and maturity of the total organic carbon is evaluated as well as the ability to create an effective fracture network within the reservoir to drain the oil and gas from the source rock. The ability to fracture the reservoir for an unconventional oil or gas prospect relies on the brittleness of the rock formation. Detailed lithology, mineralogy, and directionality of the natural in situ rock stresses also require study to optimize production (Holden et al. 2013). Creating hydraulic fractures that are perpendicular to existing natural fractures allows for maximum fracture connectivity near the well. A detailed technical assessment requires several key steps (US EIA 2013).

4.2.2 Geologic and Reservoir Study

Prospecting involves conducting preliminary geologic and reservoir characterization of potential shale basins and formations:

• Depositional environment of shale (marine versus nonmarine).
• Depth (to top and base of shale interval).
• Porosity and permeability.
• Regional fracture orientation and continuity.
• Ability of the target zone to be fractured.
• Structure, including major faults.
• Regional and local fracture systems.
• Gross shale interval.
• Reservoir pressure and temperature.
• Burial history.
• Specific formation thickness within each zone in well.
• Organically rich gross shale thickness in well.
• Total organic content (TOC) by weight.
• Thermal maturity‐the proxy is vitrinite reflectance (Ro).

4.2.3 Evaluation of Areal Extent

The prospect is refined by establishing the areal extent of the major shale gas and shale oil formations. In many deep basins, there might be several prospective zones:

• Evaluate technical literature as to regional and local geologic cross sections and basin studies.
• Generate new cross sections and basin maps based on published information and proprietary data.

4.2.4 Site‐Specific Technical Details

The next phase in unconventional prospect generation requires developing technical details for the specific area and the associated geochemical and geological conditions for each shale gas and shale oil formation within the basin:

• Evaluating the depositional environment for promising conditions (lowers risks).
• Depth criteria for the prospective area (generally >3 300 ft (1 006 m) and <16 500 ft (5 029 m)). Prospects deeper than 16 500 ft (5 029 m) that have lower permeability likely have higher drilling and production costs (raises risks).
• Higher reservoir pressures help drive oil and gas recovery (lowers risks).
• Presence of site‐specific TOC (>2%) and carbon type (types I and II) (lowers risks).
• Optimum thermal maturity (lowers risks).
• Site‐specific geographic location in geologically stable area with easy access to oil and gas conveyance system (lowers risks).
• Identify less prospective areas, high grading certain areas (lowers risks).
• High clay content in nonmarine shales from lacustrine or fluvial settings, which are more ductile and generally less responsive to hydraulic fracturing (increases risks).
• High geologic complexity with thrusts and high lateral reservoir stress (increases risks).

4.2.5 Geochemistry and Basin History

As the conversion of sediments into sedimentary rocks occurs, organic matter is turned into kerogen through diagenesis. Diagenesis of kerogen takes place generally at <2 km or 60 °C, and most of the hydrocarbon production is microbially produced methane, also called biogenic gas.

Kerogen, a precursor to petroleum compounds and bitumen, consists of organic matter, which is generally insoluble and is formed under low pressure and low temperature conditions in shallow sediments and sedimentary rocks. If sediments containing kerogen remain shallow and not deeply buried, the characteristics of the kerogen will generally remain intact (Tissot and Welte 1984).

An early coal and chemical engineer, Dirk Willem van Krevelen (1914–2001) studied kerogen sources and the maturity characteristics and temperature ranges of kerogen and petroleum. Studies of coal grades, spore color index, and vitrinite reflectance (Ro) were also studied by early coal and oil researchers trying to understand hydrocarbon maturation.

Heat causes organic matter in sediments to change into the waxy substance known as kerogen, then into crude oil, and later into natural gas as the temperature increases. Thermal maturity is a measure of the extent to which the organic material has been converted into more mature hydrocarbons. Vitrinite is a type of kerogen, and vitrinite reflectance (Ro, mean value of vitrinite reflectance of vitrinite particles in a sample) is a proxy to thermal maturity. The higher the Ro percentage (measurement in percentage of incident light reflected from vitrinite particles in a sample) value of the rock sample, the higher the maturity (US EIA 2017). Some thermal maturity indicators and associated parameters for the Ordovician Utica Formation in Ohio in the Appalachian Basin in the eastern United States are provided in Table 4.3.

The van Krevelen diagram (Figure 4.5a) is used to assess the origin and maturity of kerogen material and petroleum hydrocarbons. The diagram compares two atomic ratios of carbon compounds: the hydrogen index, which is the hydrogen to carbon ratio, is cross‐plotted against the oxygen index, the ratio of oxygen to carbon. Van Krevelen diagrams are used to plot atomic ratios of carbon compounds from individual wells or data from entire basins to identify source materials: algae, plankton, land plants and carbonized materials, and kerogen.

The main oil generation zone, called the oil/gas window, is dominated by catagenesis (Figure 4.5b). Below the oil window, the thermogenic gas zone, called the gas window, represents the thermal cracking of larger‐chain hydrocarbons by temperature and pressure into hydrocarbon gases, eventually leaving only thermogenic methane and graphite deep in the basin. A burial of sediments with depth chart (Figure 4.6) can be developed from specific well data based on geochemical analysis, spore color index, and vitrinite reflectance (Ro). This US Geological Survey (USGS) plot shows the onset of oil generation, the main oil window zone, and the deeper post‐peak oil generation zone (Pollastro et al. 2013).

4.2.6 Unconventional Resource Issues

When developing an unconventional oil or gas prospect, understanding the overall geologic complexity and lithology/mineralogy play a key role in evaluating the potential success. For geologic complexity, extensive faulting in the target shale beds can reduce recovery by limiting the potential productive length of the horizontal well. Both thrust and normal faulting can reduce individual well potential by removing reservoir sections from the adjacent productive zone.

In planning for well design, 3D seismic surveys can provide some information about the location and orientation of fault systems. Faults can also introduce water into the shale matrix, lowering the effective permeability and flow capacity. In compressive tectonic settings, thrust faults are an indication of a basin with high lateral reservoir stress, a feature that can reduce the permeability of the shale matrix and lower flow capacity (US EIA 2013).

Lithology and mineralogy are an indicator of how efficiently the induced hydraulic fractures will be able to drain the reservoir rock. Brittle shales have a high percentage of quartz and carbonate and tend to shatter easily. A vast array of small‐scale hydraulically induced fractures can form during hydraulic fracture stimulation in brittle shales, which create flow paths to drain oil and gas from the reservoir to the wellbore. Low clay content marine shales, which are more common in deep basins, shatter more easily than the high clay content nonmarine shales, which tend to be more ductile and to deform instead of shattering (US EIA 2013). Ternary diagrams showing quartz–calcite–clay ratios are frequently used to classify the mineral content of shales.

4.2.7 Estimating Oil and Gas

Developing the economics of the prospect requires evaluating the prospect risks and estimating oil and gas in place, as well as recoverable oil and gas. Original oil in place (OOIP) and gas in place (GIP) values for shale reservoirs relate primarily to net organically rich shale thickness and oil‐filled porosity or gas‐filled porosity. Other factors include reservoir pressure and temperature, as well as the thermal maturity (Ro) and burial history of the reservoir. Surface volume shrinkage for oil is the volume change oil undergoes when brought to the surface due to dissolved gas coming out of solution at surface pressures. The resource estimation equations are based on Dean (2008).

4.2.8 Original Oil in Place (OOIP)

The imperial unit is measured in stock tank barrels (STB) or in metric units in cubic meters (m³).

where

Imperial:

OOIP in STB

• Rock volume (RV) in acre‐feet = A × h × 7758
• A = drainage area in acres
• H = net pay thickness in feet
• 7758 = imperial rock volume constant: 7758 barrels per acre‐foot (API barrels (bbl); converts acre‐feet to stock tank barrels
• 1/B_o = shrinkage (STB per reservoir barrel)

Metric:

OOIP in m³

• Rock volume (RV) in m³ = A × h × 10⁴
• A = drainage area in hectares
• h = net pay thickness in meters
• 10⁴ = metric rock volume constant
• 1/B_o = shrinkage (stock tank m³ per reservoir barrel)
• A = drainage area of reservoir in acres for English units
• RVC = rock volume constant: 1.0 m³ for metric units
• h = net organically rich shale thickness in feet
• φ = porosity (dimensionless), values from cores, logs, published values, or estimates
• S_o = porosity filled by oil
• S_g = porosity filled by free gas
• S_w = porosity filled by interstitial water
• B_o = initial formation volume factor
• 1/B_o = shrinkage factor

To calculate recoverable oil volumes, the OGIP is multiplied by a recovery efficiency factor.

4.2.9 Original Gas in Place (OGIP)

The imperial unit is measured in standard cubic feet (SCF) or in metric units in 10³ m³ or standard cubic meters (SCM).

For gas reservoirs, the volumetric calculation of the original gas in place (OGIP), also called free gas, is:

Imperial:

where

• Rock volume (acre‐feet) = A × h
• A = drainage area, acres (1 acre = 43 560 ft²)
• h = net pay thickness, feet
• ϕ = porosity, fraction of rock volume available to contain fluids

Metric:

where

• Rock volume (m³) = 10⁴ × A × h
• A = drainage area, hectares (1 ha = 10⁴ m²)
• h = net pay thickness, meters
• φ = porosity, fraction of rock volume available to store fluids
• 1/B_g = gas volume factor in cubic feet per standard cubic feet. Includes gas deviation factor (dimensionless) to adjust for ideal compressibility related to pressure, absolute temperature and volume of the gas.

where

• T_s = base temperature, standard conditions, degree Kelvin (273° + 15 °C)
• P_s = base pressure, standard conditions, (101.35 kPaa)
• T_f = formation temperature, degree Kelvin (273° +°C at the formation depth)
• P_i = initial reservoir pressure, kPaa
• Z_i = compressibility at P_i and T_f
• S_g = volume fraction of porosity filled with free gas
• S_w = volume fraction of porosity filled with interstitial water

Imperial:

where

• Rock volume (acre‐feet) = A × h
• A = drainage area, acres (1 acre = 43 560 ft²)
• h = net pay thickness, feet
• ϕ = porosity, fraction of rock volume available to contain fluids
• S_w = volume fraction of porosity filled with interstitial water
• T_s = base temperature, standard conditions, degree Rankine (460° + 60 °F)
• P_s = base pressure, standard conditions, 14.65 psia
• T_f = formation temperature, degree Rankine (460° + °F at formation depth)
• P_i = initial reservoir pressure, psia
• T_i = initial temperature of the reservoir in degrees Rankin = reservoir temperature °F + 460°
• P_i = initial pressure of reservoir in psia
• z_i = compressibility factor at P_i and T_i

To calculate recoverable gas volumes, the OGIP is multiplied by a recovery efficiency factor.

A standard cubic foot of gas (at 14.73 psi and 60 °F) is equivalent to 0.028 305 855 7 standard cubic meters (at 101.325 kPa and 15 °C). A simple way to estimate gas reserves based on calculated oil reserves is the gas/oil ratio (GOR). An example ratio might be a reservoir with a GOR of 400 scf bbl⁻¹.

4.2.10 Risk Factors

Oil and gas extracted at economic flow rates will be determined by the evaluation of geologic or production‐related factors, such as shale mineralogy, reservoir properties, and geologic complexity. Each of these factors will have to be weighed to estimate the risk factors – a risk factor for each parameter such as thermal maturity, reservoir thickness, organic content, etc. (weighted from 0 to 1) as to the likelihood of the factor being optimal (value = 1) or inhibiting unconventional oil and gas production (value = 0):

• Thermal maturity and basin history.
• Optimal mineralogy for brittleness.
• High organic content.
• High reservoir thickness.
• Limited faulting.
• Large prospect area available.
• Optimal reservoir pressures.
• Surface access for operations.
• Surface access for distribution of produced oil and gas.
• Cooperative regulatory and political climate.

Conventional and unconventional oil and gas recovery through production is a percent of the total reserves in place. Unconventional oil and gas recovery estimates are summarized in Table 4.4.

Oil and gas recovery and economics (US EIA 2013) in the prospecting phase can be changed based on:

• Closer well spacing.
• Continued technological improvements in oil and gas recovery methods.
• Completion of more of the vertical net pay encountered in the well.
• Development of multiple production zones, some being less productive than the primary target.

Once the overall concept for the tight oil or shale gas prospect has been developed, the planning phase allows for the refinement of specific areas of the basin to explore or specific leases to acquire. The initial basin information may be sparse, and data might come from USGS, or other government agencies, a university graduate thesis, or research from private consultants.

Geological Information Sources

• National geological survey, such as the USGS.
• State geological survey, such as the Texas Bureau of Economic Geology.
• Private sources, such as petroleum geology consultants.
• University geology department dissertations.
• Published stratigraphic test wells.
• Geological societies publications and field trip guidebooks.
• Oil, gas, and water well logs.
• Public or private seismic data.

Rock outcrops, maps of current and past oil and gas production, and natural oil or gas seeps in the area are compiled. Conventional oil and gas fields are associated with many of the basins now being explored for shale gas and tight oil. Some of the first information may include stratigraphic information from historic oil and gas wells in the basin. Older geophysical data or geochemical studies may provide enough hints of oil and gas potential to warrant conducting additional studies. In other countries with a shorter history of oil and gas exploration, subsurface data may be limited, and wells information may not be easily available. Ultimately after the data are compiled and reviewed, if the areas remain prospective, operators will start to lease acreage from the mineral owners or bid on tracts at a government lease sale.

4.2.11 Geochemistry Studies

Geologists start with a literature search and will review published reports. In the United States, that will include obtaining reports and data from the state geological surveys, the state department of oil and gas, the USGS and other public agencies, or university publications or dissertations. Once the base maps are prepared, geologists may perform field work integrating stratigraphic information from available wells and collecting rock samples for geochemical analyses of the prospective source/reservoir rock outcrops in the basin. For unconventional source/reservoir rocks, outcropping frequently does not occur because the source/reservoir rocks lie at the deepest part of the basin trough. Surface geochemistry studies using passive vapor samplers or other techniques may be used to better evaluate subsurface conditions or document background petroleum hydrocarbon leaks in the shallow subsurface.

4.2.12 Geophysical Data Acquisition

Early in the prospecting process, geophysical data acquisition takes place, providing important subsurface information before drill bits are used to pierce the surface. One of the key questions is whether preexisting fracture zones in a prospective tight oil or shale gas formation will reopen or remain closed after hydraulic fracture stimulation. Exploration in shale gas and tight oil formations commonly uses 2D and 3D seismic surveys. The use of advanced geophysical and petrophysical techniques with a focus on the prediction of rock anisotropy, identifying the three principal stresses, and characterizing natural fracture patterns and other rock properties assists in developing geologic models for identifying the optimal available drilling locations. The prospecting phase includes the integration of geophysical data, petrophysical information from nearby wells, and geochemistry reports.

4.2.12.1 Types of Geophysical Surveys

A variety of geophysical surveys are used in unconventional resource evaluation:

• Gravity surveys
• Geomagnetic surveys
• Seismic reflection surveys

Gravity surveys detect micro‐variations in gravitational attraction caused by the differences in the density of various types of rock. Gravity data are used to generate anomaly maps from which faults and general structural trends can be interpreted and oil and gas prospects generated (BLM 2014).

Geomagnetic surveys, a more economical alternative to conventional seismic surveys, are commonly used for locating metallic ore bodies, using an instrument called a magnetometer to detect small magnetic anomalies caused by mineral and lithologic variations in the crust of the Earth. Geomagnetic surveys are used to a limited extent in unconventional oil and gas exploration in locating the shape of the basin and the approximate depth to basement rocks.

Seismic reflection surveys are the best and most common indirect method used for locating subsurface structures and stratigraphy when prospecting in tight oil and shale gas formations. Seismic energy via shock waves is induced into the Earth using one of several methods (Figure 4.7). As these seismic waves travel downward and outward into the subsurface, they encounter various rock layers, each having a different seismic velocity characteristic associated with density and other lithologic characteristics. As the wave energy encounters the interface between the rock layers, where the lower layer is of lower seismic velocity, some of the seismic energy is reflected upward. A typical seismic survey (Figure 4.8) may use four to five trucks moving behind each other and placing their vibrating plates every 75 ft (25 m) to send the seismic wave through the layers of rock. An alternative to using a vibrator truck, setting explosives in boreholes is another method of creating seismic waves for seismic reflection surveys.

With the information from geological information sources augmented with seismic data and geochemical studies, an oil and gas prospector searching for unconventional oil and gas plays can develop a drilling prospect. To develop a prospect plan, the following activities are performed:

• Research of permit requirements, setbacks and federal, state and local regulations, and an updated list of drilling moratoriums or limitations.
• Identify subsurface drilling hazards in the area such as underground mines, historic wells, and buried pipelines.
• Develop a prospect specification with a formation target zone and depth.
• Design the detailed well plans usually with a petroleum engineer.
• Evaluate property access and subsurface mineral rights status.

4.3.1 Leases

Once oil and gas prospects have been developed, leases are purchased from the mineral rights owner, sometimes the landowner, or in areas with a long history of exploration and production, frequently another company. In addition to the leases, rights of way may be needed negotiated for production wells, facilities, tank batteries, pipelines, power lines, and access roads. Leases frequently come with operator obligations to drill a well and establish production within a period detailed in the lease. Surface rights and mineral rights may be owned by different owners, creating an uncomfortable situation and possible disruption for the uncompensated landowner when drilling and production begins.

4.3.2 Drilling Permit Process and Public Participation

Drilling permits are part of the field planning process after detailed prospect evaluation has occurred. After an operator decides to drill a well, the exploratory well, the access road, and tank storage or pipeline must be designed, surveyed, and staked. Numerous local, state, and possibly federal permits may be required. Production of environment impact reports and establishing and documenting background conditions should be integrated into the planning phase of the project. Water sourcing and waste disposal issues must be addressed during this phase. Notifications and environmental documents may be produced. Public meetings and community outreach should be part of the planning process, and good communications, transparency of decisions, and disclosing all chemicals used on‐site or in well stimulation techniques increase the chances of more favorable community reception.

Many of the tools and equipment used in conventional drilling (Baker 1979) are also used for unconventional oil and gas targets. Unlike conventional drilling programs and production, which are generally limited to geologically smaller structural areas, such as an anticline, shale gas and tight oil production occurs over entire basins and may exist in dozens of contiguous counties. Drilling and production are large‐scale industrial processes, which can be the source of excessive noise, odors, dust and air emissions, traffic, and other forms of pollution. Due to the high cost of drilling in labor, equipment rental, and supplies, drilling operations are usually running continuously, 24 hours a day, 7 days a week with the potential to tax local infrastructure, create significant nuisances for nearby landowners and residents, and impact available resources. Public meetings and discussions should focus on impact mitigation measures, environmental protection planning, health and safety issues, and pollution prevention.

4.3.3 Drilling Pad Construction

After the permit has been issued, but before the pad is constructed, baseline environmental conditions (drainage, vegetation, faults, erosion, acid drainage, environmental damage, etc.) verified with photographs are identified during an initial pre‐construction inspection, prior to any surface disturbance. Later inspections by a competent person, during construction and drilling, documents that surface activities and disturbance are within the limits established by the drilling permit.

Once the permits are approved, a variety of earth moving equipment including track hoes, track‐mounted and rubber‐tired bulldozers, scrapers, and motor graders are used to construct the drilling pads and any additional access roads.

Moving equipment to the construction site requires moving several loads, and frequently some of the equipment is overweight and over width for traveling over public and private roads. Existing roads and vehicle routes may require improvements in places, and occasionally, culverts and cattle guards may be needed to be installed.

The length of the access road varies. Generally, the route is selected to reduce impacts. Environmental factors or the preferences of the landowner might dictate a longer route. Roads are usually constructed 14 ft (4 m) wide for single lane or 24 ft (7 m) wide for double lane. Other design decisions are whether to construct a single‐well pad or a multiple‐well pad. Soil texture, steepness of the topography, and moisture conditions might require surfacing such as gravel, rather than native soil. Erosion and dust control should be implemented for the well pad and access road.

The amount of area disturbed for construction of the drill pad depends largely on the steepness of the slope. Sites on flat terrain usually require only slight removal of the topsoil material and vegetation. Drilling sites on ridge tops and hillsides are constructed by cutting and filling portions of the location, which is more costly and of longer duration. The majority of the excess cut material is stockpiled in an area that will allow easy recovery for site restoration. Casting removed soil down hillsides or into drainage areas creates erosion potential and unstable soil surfaces. Since the exploration–production process (see Figure 4.4) ends with site restoration, all soil material suitable for plant growth is removed and stockpiled in a designated area for later reuse.

The amount of level surface required for safely assembling and operating a drilling rig varies with the type of rig, the depth, type of the well, and the projected number of wells on the drilling pad. The size of a drilling pad is primarily determined by the capacity of the reserve pits to hold the cuttings from all wells drilled on the pad, as well as having sufficient room for drilling and well completion operations. Although variations will exist, a reasonable size for a single‐well pad is ~4 acres (1.6 ha), about 8 acres (3.2 ha) for an eight‐well pad, and about 12 acres (4.9 ha) for a 16‐well pad. The locations of well pads, roads, drainages, and utilities should be carefully optimized.

4.4.1 Drilling Rig

Rotary drilling rigs (Figure 4.9) exert downward pressure on rotating drill rock bit at the bottom of the borehole (Figure 4.10). The derrick and associated hoisting equipment bear a majority of the weight of the drill string during the drilling process. The drill string consists of the drill pipe and the bottom‐hole assembly. The drill pipes are about 30 ft (9 m) in length, although longer drill pipes have been used for deeper holes. The bottom‐hole assembly generally consists of drill collars, subs (including stabilizers), reamers, shocks, hole openers, connection adapters, measuring and steering tools, and the drill bit. Downhole drilling motors can also be used to assist in steering for directional or horizontal drilling. The combination of the rotary motion of the drill string and the weight on the bit and the rotary action gouges the rock at the bottom of the open borehole. Powered by a series of diesel engines, a square or hexagonal rod, called a kelly, creates the downhole rotary motion of the drill string. The kelly fits through a square or hexagonal hole in a large turntable, called a rotary table. The action on the drilling rig floor is dominated by the spinning rotary table, and as the drill bit advances, the kelly slides down through it. When the kelly has gone as deep as it can, about the depth of the drill pipe, it is raised, and a new piece of drill pipe is attached in its place. (A variety of compounds are commonly found at drilling and production sites (Table 4.5)).

Rotary drilling is an iterative process, and the drill pipe is then lowered into the borehole and the kelly is reattached, and drilling recommences. When the bit becomes dull, it is necessary to remove the drill string and replace the bit. This is a time‐consuming process called tripping and consists of withdrawing three drill pipes in 90 ft (27 m) sections until the old drill bit is out of the hole. Another rotary method uses a powerful (1000 hp) top drive motor suspended from the top of the derrick to rotate the drill string during the drilling process. Drilling bits (Figure 4.11) are carefully selected for the formation and depth and to optimize drilling safety and speed. Coring tools with hardened teeth cut rock cores (Figure 4.12) for lithologic characterization and testing.

Additions to the general theme of rotary drilling include coiled tubing drilling, which has found use in horizontal wells. Coiled tubing drilling or flexible hose drill string refers to a very long bendable metal pipe, normally 1″ (2.5 cm) to 3.25″ (8.3 cm) in diameter, which is supplied spooled on a large reel for specific drilling situations such as directional drilling and well workover processes. Originally developed in the 1920s, and improved upon continuously since, coiled tubing has been used for both conventional and unconventional oil and gas production. Coiled tubing fracturing provides the ability to accurately select fracture multiple zones during the hydraulic fracturing process.

4.4.2 Circulation System

The drilling fluid circulation system consists of a series of pumps, pipes, and tanks to circulate the drilling fluid, also called drilling mud. Drilling mud is circulated through the drill pipe to the bottom of the hole, through the bit (Figure 4.13), up the annulus, which is the space between the outside of the drill pipe and the borehole. The drilling mud provides important functions in the drilling operation:

• Lubricate and cool the bit and drill string.
• Remove and transport rock cuttings up the annulus to the surface.
• Provide borehole stability.
• Help with suspending the weight of the drill string and casing.
• Suspend solids in the drilling mud.
• Control subsurface pressure.
• Transmit hydraulic energy to the downhole tools and instruments.

The drilling mud moves up the annulus to the top of the well across the shale shaker, which is a screen that separates the rock cuttings from the drilling fluid. The drilling mud flows into holding tanks from which the finer sediments settle from the drilling fluid before it is pumped back down into the well. The drilling mud is maintained at a required weight and viscosity to cool and lubricate the bit, reduce the drag of the drill pipe on the sides of the borehole, seal off any porous zones, counterbalance the formation pressure while drilling and contain formation fluids to prevent a blowout, prevent the uncased or open borehole from collapsing, and bring the rock fragments to the surface for lithologic characterization, analysis, and disposal. Should the mud chemistry or density of the fluid be calculated incorrectly, dangerous well conditions such as loss circulation (low pressure in well) or well kicks (high pressure in well) can occur.

Various drilling fluids and chemical additives (Table 4.6) are used in maintaining the mud at the appropriate viscosity and weight and to counter the extreme temperature, pressure, and geochemical conditions in the subsurface (OSHA 2014). Some of the compounds are the same chemicals used in the hydraulic fracture stimulation operations. Most of the drilling fluid consists of a base or carrier liquid, such as water, oil‐based muds (diesel or mineral oil), or synthetic compounds. A synthetic compound‐based drilling fluid was recently developed to replace oil‐based muds and will have generally oleaginous or oil‐like characteristics combined with specific additives. Due to their lower cost, water‐based drilling fluids are most commonly used. Weighting or density additives include barium sulfate or barite and clays such as bentonite or attapulgite. Other chemicals used in drilling muds include corrosion inhibitors, which decrease the corrosion rate of steel and iron drilling tools; flocculants, which cause suspended particles to group together, so they can be removed from the fluid at the surface; and dispersants, which improve the separation of particles to prevent settling or clumping. Biocides control microbial growth and help reduce the fermentation of drilling mud. Fluid loss reducers and lost circulation materials limit the loss of drilling fluid into an underpressurized or high‐permeability formation. Many of these chemical additives are used together in customizing the drilling fluid characteristics for a particular subsurface condition.

Regardless of the type of drilling mud used, typical contaminants of interest that require periodic monitoring for significant changes are pH, electrical conductivity, sodium adsorption ratio (SAR), cation exchange capacity (CEC), exchangeable sodium percentage (ESP), and total metals. Other constituents of concern include oil and grease and total petroleum hydrocarbons. Drilling fluids usually have a pH that falls within the alkaline range (pH > 10). This high pH is a result from the addition of lye, soda ash, and other caustics, which allows for the dispersion of clay and increased effectiveness. Weathering and aging causes a decrease in the overall pH. Soil salinity is measured by determining the electrical conductivity. This is an important test for soils and waste because of the potential for high brine content that adversely affects plant growth and water quality. Soils exhibiting an electrical conductivity more than 8.0 mmhos cm⁻¹ usually require some manner of management or remediation. SARs are determined to assess potential sodium damage from a waste material. Used in conjunction with electrical conductivity, potential damage associated with sodium salts can be ascertained. An SAR < 3 can restrict such materials for land disposal. Acceptable metal loading in muds are evaluated for CEC. Measured in meq/100 g, CEC values are required to estimate the ESP. Excess sodium typically results in a general lack of structural stability among soil particles and impeded water infiltration. Combined excess salinity and sodic conditions can limit remediation efforts (i.e. remove excess salts from the root zone) due to inherent slow infiltration and percolation characteristics.

Total metal analysis provides a good indication for all metals except barium that is best analyzed under the protocol set forth by the Louisiana Department of Natural Resources. Total metals include arsenic, barium, cadmium, chromium, mercury, lead, selenium, and zinc. Although seldom a significant problem, elevated concentrations of certain metals in soil or waste materials are labile. The metals of most concern in drilling muds are barium, chromium, lead, and zinc.

The presence of petroleum hydrocarbons in drilling muds or waste is typically due to the introduction of crude oil from a producing formation and diesel or mineral oil that is added to drilling muds. Although diesel is likely to be the most common contaminant, diesel‐affected soil and waste materials can be easily remediated via a variety of options. Subsurface biogeochemistry is complex, and the variations in drilling fluid additives reflect adjustment to changes in redox chemistry, pressure, temperature, pH, etc. The same compounds may be used for a variety of different purposes.

The drilling mud circulating system, a key system on the drilling rig, includes the drill bit, drill collar, annulus, drill pipe, kelly, and swivel. The mud flows through the mud return line upon its return to the surface from the borehole to the shale shaker and then to the adjacent desander, desilter, and degasser back to the mud tank. Rock cuttings are collected from the shale shaker for inspection to evaluate lithology, drilling mud characteristics, and evidence of hydrocarbons. The drilling mud then passes through the suction line, and the mud pump circulates the mud through the discharge line, the stand pipe, through the rotary hose and the swivel, back to the kelly and into the drill pipe.

4.4.3 Logging Equipment

Logging provides a prime example of the difference between raw data and useful information. It is only with a competent log analyst that data from mud logging, wire line logging, and logging while drilling (LWD) can be integrated to develop site‐specific information about reservoir conditions and unconventional oil and gas potential. Downhole logging data can also be used for detailed reservoir modeling and rapid economic projections. A variety of key reservoir characteristics as summarized by Bateman and Alzahabi (2016) can be estimated from these types of logging methods:

• Overall geologic characterization.
• Geochemistry.
• Isotope ratios, such as Th/U.
• TOC.
• Thermal maturity level of the hydrocarbons.
• Types of fluids and gases present.
• Lithologic characteristics.
• Mineralogy.
• Sedimentary analysis.
• Porosity and permeability.
• Gas saturation and GOR.
• Structural features and layering.
• Structural features.
• Stress determination and fracture analysis and orientation.
• Effectiveness of well stimulations and completions.
• Optimal azimuthal horizontal lateral well placement.

4.4.3.2 Wire Line Logging

Downhole logs (Figure 4.14) are obtained by running various petrophysical tools into the borehole on a wire cable to identify rock properties of the subsurface and delineate specific geologic units. Logs are usually run at specific target depths usually where casing strings are installed (Table 4.7). Some logs are run before the casing (such as caliper logs, gamma, resistance, spontaneous potential, temperature, and television logs), while cased logs are used to evaluate characteristics not affected by steel casing and can provide evidence of the casing‐cement bond and cased borehole conditions. Logging tools are used to measure water resistivity, hydrocarbon saturations, natural gamma radiations, porosity by density, fracture identification from image logs, nuclear magnetic receptivity and sonic measurements, permeability, pressure, temperature, borehole geometry, and subsurface location. Logs are used to evaluate whether the borehole has the potential for a successful well completion or is a dry hole. Lithologic interpretation is used to differentiate between: sandstones, shales, carbonates, coals, and other minerals. Logs are also used to delineate the various geologic horizons and characteristics; porosity, thickness, and saturation of hydrocarbon zones; and location and thickness of fresh, usable, and unusable water. Prospective intervals containing hydrocarbons are identified and measured on logs, and the formation is perforated and stimulated during the completion program at these zones, based on the log interpretation.

Type of log	Varieties and related techniques	Properties measured	Potential applications	Required hole conditions	Other limitations
Spontaneous potential (SP)	Basic SP log	Electric potential caused by differences in borehole and interstitial fluids	Lithology, shale content, water quality, freshwater versus saline water	Uncased hole filled with conductive fluid	Salinity difference needed between borehole fluid and interstitial fluids correct only for NaCl fluids
Single‐point resistance	Conventional and differential	Resistance of rock, saturating fluid, and borehole fluid	High‐resolution lithology, fracture location by differential probe	Uncased hole filled with conductive fluid	Not quantitative; hole diameter effects significant
Multielectrode	Normal, focused, or guard	Resistivity, in ohm‐meters, of rock and saturating fluids	Quantitative data on salinity of interstitial water, lithology	Uncased hole filled with conductive fluid	Normals provide incorrect values and thicknesses in thin beds
Gamma	Gamma spectral	Gamma radiation from natural or artificial radioisotopes	Lithology; may be related to clay and silt content and permeability; spectral identifies radioisotopes	Any hole conditions, except very large, or several strings of casing and cement	One of the most commonly run logs in the suite
Gamma–gamma	Compensated (dual detector)	Electron density	Bulk density, porosity, moisture content, lithology	Optimum results in uncased; qualitative through casing or drill stem	Severe hole diameter effects
Neutron	Epithermal, thermal, compensated activation, and pulsed	Hydrogen content	Saturated porosity, moisture content, activation analysis, lithology	Optimum results in uncased; can be calibrated for casing	Hole diameter and chemical effects
Acoustic velocity	Compensated wave form, cement bond	Compressional wave velocity	Porosity, lithology, fracture location and character, cement bond	Fluid filled, uncased, except cement bond	Cannot be used to identify secondary porosity; cement bond and wave form require expert analysis
Acoustic televiewer	Acoustic caliper	Acoustic reflectivity of borehole wall	Location, orientation, and character of fractures and solution openings, strike and dip of bedding, casing inspection	Fluid filled, 3–16 in diameter	Heavy mud or mud cake attenuate signal; very slow logging
Caliper	Oriented, four‐arm high‐resolution bow spring	Borehole or casing diameter	Borehole diameter corrections to other logs, lithology, fractures, hole volume for cementing	Any conditions	Significant resolution difference between tools
Temperature	Differential	Temperature of fluid near sensor	Geothermal gradient, in‐hole flow, location of injection water, correction of other logs, curing cement	Fluid filled	Accuracy and resolution of tools varies
Conductivity	Resistivity	Most measure resistivity of fluid in hole	Quality of borehole fluid, in‐hole flow, location of contaminant plumes	Fluid filled	Accuracy varies, requires temperature correction
Flow	Spinner, radioactive tracer, thermal pulse	In borehole flow	In borehole flow, location and apparent hydraulic conductivity of permeable interval	Fluid filled	Spinners require higher velocities; needs to be centralized
Radar	Single‐borehole reflection, cross‐hole tomography, borehole‐to‐surface measurements	Radar wave reflection	Rock structure	Dry or fluid filled, uncased or PVC‐cased (water well) borehole	Metal affects measurements
Electromagnetic induction	Induction log	Electromagnetic conductivity	Lithology, water quality	Fluid filled, uncased or PVC‐cased (water well) borehole	Metal affects measurements

4.4.4 Fluid Management System

Fluid management is one of the most critical environmental aspects of drilling and hydraulic fracture stimulation. Drilling‐derived and well‐derived liquids and solids include drilling muds and cuttings, flowback waters (flowback), production water, equipment cleaning waters, and cooling waters (Table 4.6). The purpose and examples of specific compounds show that some operations such as drilling and hydraulic fracturing can use the same chemicals for different functions, such as biocides and corrosion inhibitors.

Drilling muds consist of a base fluid, a weighting agent, flow agents, and other compounds to optimize drilling, control bacteria, and limit corrosion. Details of the specific chemicals used in drilling and hydraulic fracture stimulation are found later in the chapter. Regardless of the specific compounds used in the drilling muds or hydraulic fracturing fluids, the standards of liquid and solid waste management have evolved over time:

• Open fluid impoundments
• Closed containment systems
• Closed‐loop system

Open fluid impoundments have been used for over 150 years in the oil and gas industry. Historically, unlined pits were used to store drilling‐derived wastes, and leakage of toxic chemicals near and beneath unlined reserve pits at exploration and production sites is common. Many current operators use lined fluid impoundments, reserve pits, or mud pits, which are constructed close to the rig (Figure 4.15). The pits are usually square or oblong, but sometimes in another shape to accommodate the lease shape or topography. A reasonable reserve pit depth is about 8 ft (2.4 m) to 12 ft (3.7 m) deep, but it could be deeper (with smaller length and width) to compensate for deeper drilling depths (with a need for a larger capacity). A minimum of 2 ft (0.6 m) to 3 ft (0.9 m) of freeboard is recommended, and the open pits should be covered with bird netting. Lined pits have at least two layers of liners, with a leak detection and alarm system between the liners. The synthetic flexible geomembranes, such as impermeable chemically resistant chlorosulfonated polyethylene (CSPE) and high density polyethylene (HDPE) liners must have the seams sealed and inspected during installation (Figure 4.16). Lined ponds, whether containing drilling fluids (double lined), dairy wastes (double lined), industrial chemicals (double lined), or stormwater (single lined), frequently use 60‐mil HDPE liner material sealed with a wedge seamer joining the panels together. The seaming of double liners creates an air gap between the two seams. The air gap is sealed on both ends of the seam and tested to hold pressure of 25–30 psi (172–207 kPa) for 5 minutes. Pond liner standards have been developed by a variety of organizations, including ASTM International and the Geotextiles Institute. Natural liners, such as clay with a hydraulic gradient of 1.0 × 10⁻⁷ cm s⁻¹, have been used on drill sites. As with any fluid containment system, inspections and monitoring should be performed daily or more frequently, as needed. Lined fluid impoundments are not a best management practice for safely storing drilling muds, hydraulic fracture stimulation liquids, flowback, or production fluids.

For significantly better control of fluids on the drilling pad, some operators use a variety of closed containment tanks, which have a higher initial cost than lined pits. The system uses tanks to store fluids generated on the drill pad. For control and storage of flowback water during the hydraulic fracture stimulation process, dozens of side‐by‐side steel fluid tanks are used by some operators (Figure 4.17). Each fluid tank commonly has 21 000 gal (80 000 liter) capacity, and tanks can store drilling fluids, frac fluids, flowback, or production liquids. Some regulatory agencies require best management practices for drilling fluid management. In the state of New Mexico, lined pits are not allowed, and all aboveground tanks containing fluids other than freshwater must be contained in an impermeable bermed enclosure to contain a volume of one‐third more than the total volume of the largest tank or of all interconnected tanks. All below‐grade tanks in New Mexico must have secondary containment and a leak detection system. When the tank system is full and needs pumping, the fluids are extracted in a batch process and usually transported off‐site for treatment, reconditioning, and possible reuse or off‐site disposal.

The best and the highest initial cost option for fluid management at a drill pad is the closed‐loop drilling system, also called pitless drilling. This integrated system reduces the amount of drilling waste, recycles drilling fluids, reduces drilling costs, conserves water, and minimizes soil and groundwater contamination from drilling wastes. Closed‐loop drilling uses centrifuges that separate solids (cuttings) from the drilling mud liquids (Rogers et al. 2006, b). If shallow groundwater is encountered while digging the reserve pit, a closed‐loop drilling system is recommended. On Bureau of Land Management leases, closed systems are mandatory for operators using oil‐based mud. In addition, the mud and cuttings must be recycled or disposed of in an approved manner (BLM 2014).

Rigs used for drilling into tight oil and shale gas formations are portable and include tall derricks that handle the tools and equipment that descend into the borehole or well. The modular drilling equipment is transported to the drill site by trucks or barges. Moving a land‐based drill rig might require 30–40 truck trips of construction equipment over public highways and private roads.

Water for drilling and well completion may be hauled or piped to drilling pad locations. Water sources are usually commercial water sources or recycled water if drilling is below the surface casing and freshwater aquifer zones. When drilling commences, and as long as it progresses, water is continually transported to the rig location, unless an adequate water well exists or can be drilled on‐site, which is rare. Roughly 5 000 barrels of water is required to drill and 23 000 barrels required for completion operations for an oil or gas well to the depth of 9 000 ft (2 750 m) or greater. Generally, water required for completion operations is recycled to the extent practical. More water would be required if circulation is lost, or permeable zones that cannot withstand the pressure of the drilling fluid are encountered (BLM 2014), and as such, adequate water storage areas need to be designed.

4.4.5 Drill String

The drill string is the column of pipe that conveys the drilling fluid through the mud pumps and transmits the torque through the kelly drive or top drive to the drill bit at the bottom of the borehole. The bottom‐hole assembly includes the drill bit, drill collars, drilling stabilizers, and MWD tools. A series of heavy thick‐walled drill collars near the bit provides additional weight on the drill bit. Stabilizers keep the bottom‐hole assembly centered in the borehole. A heavyweight transition drill pipe may be used between the bottom‐hole assembly and the drill pipe. The drill pipe consists of the majority of the drill string and consists of pieces typically about 30 ft (9 m) in length. To save time tripping in or out of the hole, 90 ft (27 m) stands consisting of three 30 ft (9 m) drill pipes joined together are handled by larger, modern drill rigs. Fishing tools (for lost or separated drill pipe in the borehole), jars (to loosen stuck drill pipe), and other drilling specialty tools are added to the drill string to address specific downhole conditions. The significant advances in downhole directional steering have been a significant drilling advancement, allowing for the production of unconventional oil and gas resources.

Directional drilling and horizontal drilling use a hydraulic downhole motor powered by the flow of drilling mud down the drill pipe. The downhole motor can rotate the drill bit without rotating the entire length of drill pipe between the drill bit and the surface. The separation of rotation motion of the downhole motor and the drill bit allows the bit to drill a path that deviates from the orientation of the drill pipe. Horizontal wells or production drain holes, used almost exclusively for drilling targets in tight oil and shale gas formations, begin at the surface as vertical wells. The drilling progresses, and conductor pipe and surface casing are installed to protect and seal off shallow aquifers and deeper aquifers, respectively, from the much deeper natural gas, crude oil, and brines. When the drill bit is a few hundred feet above the target zone in a vertical well, the drilling is stopped.

While the drilling is stopped, the drilling mud continues to be circulated to maintain subsurface control. Then the drill string is removed and reinstalled with a hydraulic motor attached between the drill bit and the drill pipe. After the downhole motor is installed between the drill bit and the drill pipe, the newly reconfigured drill string is lowered back down the borehole at the kickoff point. The drill bit creates a path that steers the borehole from vertical to horizontal over only a few hundred feet. Once the borehole has been steered to the proper angle, straight‐ahead drilling resumes and the borehole follows the designed trajectory to the producing zone. Keeping the well within a target zone of a thin rock unit, such as 100 ft (33.5 m), requires careful navigation. Downhole instruments are used to determine the azimuth and orientation of the drilling. This information is used to steer the drill bit.

Horizontal drilling is significantly more expensive than installing a vertical well in the same formation; however, the amount of net pay is greatly increased. When combined with hydraulic fracturing stimulation, an unconventional oil or gas well can cost up to three times as much per foot as drilling a vertical well. The extra cost is usually recovered by increased production from the well. Depending on local geologic conditions, these drilling and production methods can multiply the yield of natural gas or crude oil from a horizontal well by up to 10–20 times compared with a vertical well completed in a similar manner in the same zone. Directional drilling includes not only the subsurface motors and controls, such as MWD, but the oil and gas industry has developed several technologies to improve overall efficiency, such as using advanced drill sensors and global positioning technology to ensure the success at locating and producing from distant target zones, as thin as 9 ft (3 m) thick (Figure 4.18). Rapidly developing and continuously improving drilling and production technology has paid off for oil and gas operators by precisely controlling the direction and depth of each completed producing well. Other tools such as whipstocks, bottom‐hole assembly configurations, 3D measuring devices, and other specialized drill bits and motors have enabled a single surface drilling pad to service multiple wells drilled at various angles, tapping into formations containing crude oil and natural gas reserves more than a mile deep and miles away from the surface rig location.

4.4.6 Casing System

A series of nested steel casing strings separated by specialized cement isolates productive hydrocarbon zones from unproductive formations and protects groundwater resources. The casing strings are installed from the largest‐diameter to the smallest diameter casing and usually consist of conductor, surface, intermediate, and production strings placed in the drilled borehole to provide a conduit for completion operations and production, to attach subsequent casing strings, to provide borehole stability, to isolate specific formations or zones, and to connect the blowout preventer (BOP) at the surface. Casing consists of steel pipe composed of ~40 ft (12 m)‐long pipes that are threaded together and are used for subsurface control. Casing is cemented into the walls of the borehole to protect against migration of gases and fluids within the open borehole and to isolate the productive hydrocarbon zones, so they can be completed and produced without interference from water zones or nearby underpressured or overpressured formations. The casing (Figure 4.19) and cement design should include borehole deviation, casing depth, borehole conditions and environment, and placement of centralizers. For horizontal or angled boreholes, casing centralizers are placed on the outside of the casing to center the casing string in the center of the borehole.

Conductor casing protects the borehole from sloughing of unconsolidated surface sediments and isolates the shallowest groundwater from the contents of the borehole. Also called conductor pipe, this is the largest‐diameter casing and is designed to be large enough to allow subsequent smaller casing strings to be installed as the borehole is drilled deeper. The conductor casing is installed from the surface to about 80 ft (25 m) to 150 ft (45 m) below ground surface. The conductor casing is not always required.

Surface casing is installed for well control and to protect deeper but important water sources from subsurface contamination by oil and gas drilling and production operations. Surface casing is highly regulated and should always be set to a depth greater than the deepest reasonably developed freshwater aquifer. Usable water resources could exist at great depths. Deeper water zones that are not considered important groundwater resources frequently have high total dissolved solids (TDS) and high salinity or are brines. The surface casing can be set on the bottom from about 2000 ft (600 m) or more, and the casing is run to ground surface. The surface casing is lowered into the borehole from the surface to just above the bottom of the borehole, leaving a space at the bottom of the casing string. The cement is pumped down inside the casing string and enters the open borehole space at the bottom of the casing string. Pressure from the pumps forces the cement up from the bottom of the casing string into the annular space between the outside of the surface casing and the borehole walls. Continued circulation until the cement returns to the surface ensures that the entire annular space is filled with sealing material and no voids exist. For the surface casing to protect and isolate important aquifers from deeper hydrocarbon zones, a strong cement bond between the casing and the borehole wall must be confirmed. A cement bond logging tool is run in the cased hole, and the logs are interpreted for evidence of the quality of the annular seal, inspecting for possible cement defects including voids, bridging, or cracks. The cementing process is used for the other casing strings as well.

The installation and cementing of the surface casing is a critical aspect of environmental protection of local groundwater resources. The depth of hydraulic fracturing and production zones in a basin should be compared with the depth of groundwater resources and the installation of surface casing.

Intermediate casing is generally cemented in place after the surface casing and before the production casing is installed. The intermediate casing string is designed to provide protection against borehole instability caused by sloughing of abnormally pressured or weak formations. Intermediate casing allows engineers to change the density and characteristics of the drilling fluids necessary for the borehole control of deeper rock formations. In some situations, intermediate casing may not be needed.

Production casing is usually installed from the surface down to the top of or into the producing zone. The production casing string is set across the target zone and connects the producing formation and the primary completion components. Production casing is also used to pump hydraulic fracture stimulation fluids into the producing formation without contacting other formations in the borehole. If the petrophysical logs do not indicate that economic amounts of hydrocarbons were discovered, the borehole is abandoned or plugged and the time‐consuming and expensive task of installing production casing is not expended. Specialized tubing may also be used under certain situations. Production may be directly from the formation or open hole, without casing or through perforations in the production casing.

Blowout preventer is an important piece of safety equipment to prevent overpressured fluids or gases from reaching the surface. Cement is placed in the annulus of the surface casing from the casing shoe (at depth) to the ground surface. The surface casing is the first string on which BOP equipment is installed. The BOP equipment allows the well to be shut in at any time that conditions warrant, protecting against unanticipated formation pressures and allowing safe control of the well. BOP equipment is tested and inspected regularly by both the rig personnel and regulatory agencies.

4.4.7 Cementing System

Cementing is one of the most important engineering design and field implementation projects for subsurface environmental protection available on the drill pad. Cement fills and seals the annulus between the casing strings and the borehole. If done correctly, an impermeable seal created by the cement will keep the casing string stable and strong, isolate and contain production fluids from leaking into shallow aquifers, and prevent casing corrosion. If done poorly, or if the cement develops cracks or microfractures over time, the sanitary seal between the surface and the production fluids can be compromised.

Placing cement in the annulus between the casing and the borehole walls is a critical factor in providing a hydraulic seal and protecting water resources. Cementing systems and cementing design can be used to isolate specific oil or gas production zones, isolate saltwater brines from the production zone, or protect water resources. In addition, the casing protects the casing from corrosion and provides structural support for the casing and acts to centralize the casing in the borehole. Cementing also isolates the casing seat for subsequent drilling. Casing can be moved into optimal position while cementing by drill string rotation; raising or lowering the drill string is called reciprocation. A written cementing plan should describe the borehole environment and downhole conditions, well type, borehole conditioning and mud properties, casing and cement program, type of well completion or abandonment procedures, circulation rate, filter cake removal, and any special issues, such as fluid loss zones and high‐pressure zones.

4.8.1 Technology Improvements

The general theme of high‐volume hydraulic fracturing has remained the same for over a decade. Technological improvements will continue to be made with dramatic production results. Nowhere are these improvements more apparent than in the Bakken Formation production area in North Dakota. Over nine years (2006–2014), data from the North Dakota Department of Mineral Resources (NDDMR) shows the increase of the average lateral length of the drain hole and an increase in the number of fracture stages. These two improvements allow for increases in the volumes of fluid injected per well. The average lateral length of the well drain hole in 2006 was 6200 ft (1890 m), and by 2014, the same average length was 9700 ft (2957 m), an increase of 56%. Due to the increased horizontal drain hole length, average fracturing fluid volume also increased from 9 900 bbls (1 574 m³) in 2006 to 89 700 bbls (14 261 m³) in 2014, an increase of 9 times (EERC 2016). These technology improvements allow for more drainage per well, lower overall costs of resource extraction per field, and the need for less well pads and wells. Below is a description of the hydraulic fracture stimulation process.

4.9.1 Four‐Phase Treatment

A single stage of sequenced hydraulic fracture treatment consists of generally four phases with associated substages; however, specific phases can be repeated. The four phases or substages are:

• Phase 1: Acid injection.
• Phase 2: Slickwater injection.
• Phase 3: Proppant sequence injection broken into numerous subphases.
• Phase 4: Flushing phase.

After the documentation and detailed testing of the hydraulic pumps and other equipment has been completed, the hydraulic fracturing process begins. An example of a single‐stage fracture treatment event from the Marcellus Formation in western Pennsylvania shows a total volume of 538 000 gal of injected water (2.0 million liters) (Table 4.9) (US DOE (2009) as seen in Arthur et al. (2008)). If the well has 5000 linear feet (1524 m) of horizontal borehole, there might be five stages, each about 1000 linear feet long. If there are 5 stages and each stage uses about 500 000 gal (1.9 million liters) of hydraulic fracturing fluids, the total water used for the five stages would be 3 million gallons (11.3 million liters). The amount of water and various chemical additives are shown as a pie chart (Figure 4.37). Table 4.10 lists the classes of common chemical additives with their function and common uses (US DOE 2009). High‐viscosity fracturing fluids are used to create large but fewer reservoir fractures. High rate fluid injection, called a slickwater injection, creates a set of numerous small microfractures. Fracture and microfracture monitoring is performed to evaluate fracture geometry and connectivity. Estimated water needs in selected shale basins are summarized in Table 4.11 (Figure 4.34).

4.9.1.3 Treatment Phase 3: Proppant Sequence Injection

After the slickwater pad has been pumped and the pressure has subsided, the proppant sequence injection begins with a large volume of solids. Examples of proppants include natural quartz sand (Figure 4.35, top) and manufactured ceramic proppants (Figure 4.35, bottom). The purpose of the proppant is to keep the existing intersected natural fractures and induced fractures open and connected to allow petroleum hydrocarbons to drain from the formation and to enter the well. During phase 3, the fluid injection pumps increase the hydraulic pressure again, squeezing in proppant materials to open the newly made fractures (Figure 4.36). Proper proppant selection to match the size of the proppant to the forecast fracture size is critical to well production success. The initial proppant in the Marcellus Formation example is a 100‐mesh sand, which is a fine‐grained sand. About halfway through the proppant sequence injection in this example, the proppant size is increased to a 40/70 mesh sand, which is a medium‐ to fine‐grained sand. In the Marcellus example, the proppant sequence injection consists of a total volume of 420 000 gal (1.6 million liters) of water with the proppant media, all of it at 3 000 gpm (11 356 lpm). The proppant injection phase is broken into 15 subphases and starts with 50 000 gal (189 271 l) at the first subphase and may contain a dilute acid solution using an acid such as hydrochloric acid (HCl). The subphases generally start with larger volumes of water and a smaller‐size proppant, a reflection of the ability of the formation to initially accept the pumped fluids. Later subphases decline from a high volume of 50 000 gal to a low volume of 10 000 gal (37 854 l) for the last subphase (Figure 4.35).

4.10.1 Flowback Fluids

After all injection of fracking fluids and flushing water has been injected, the flowback begins (US DOE 2009). Flowback includes the fluids that return to the surface during and after the completion of hydraulic fracture stimulation process. Flowback includes the fluid used to fracture the target zone, in the example above, the Marcellus Shale. The fluid also contains clays, chemical additives, dissolved metal ions, and TDS. The fluid frequently has a cloudy appearance from the high levels of suspended particles. Most of the flowback in a formation occurs in the first 1–20 days (18–37% flowback of injected frac fluid), while the rest can occur over 30–90 days, where the total flowback volume is 20% to 44% of the volume of frac fluid that was initially injected into the formation (US DOE 2013a, b; Abdalla and Drohan 2010; PSE 2011). The rest of the hydraulic stimulation fluid (phase 1 through phase 4, above) remains trapped in the pores and lattice structures of the hydrated minerals (of the Marcellus Formation). At some point, petroleum hydrocarbon breakthrough into the borehole and the water recovered from an oil or gas well makes a subtle transition from flowback water to coproduced water. This transition point is identified based on the rate of return of the fluids measured in barrels per day (bpd) and evaluation of the chemical composition of the fluids. Flowback fluids are typically produced at a higher flow rate over a shorter period of time, usually >50 bpd (7.9 m³ day⁻¹) than the coproduced water, which is characterized by a generally much lower flow rate.

The US EPA (2013a, 2015a, b, 2016a) evaluated other compounds in the influent water, influent blend (fracturing fluid), and the flowback fluids. The studies analyzed volatile organics, semivolatile organics, pesticides, organophosphorus pesticides, PCBs, metals, and radiological material. Not surprisingly, the hydrocarbon coproduced water contained benzene, toluene, ethylbenzene, and xylenes, which are natural components of crude oil as well as fuels refined from petroleum hydrocarbons. Most of the volatiles and semivolatile compounds on the US EPA list were man‐made industrial chemicals that were not generally found in produced waters but reflected flowback fluids. Pesticides were not found in the produced water in the EPA study.

In some cases, flowback fluids might be treated and then discharged under permit into the local municipal wastewater treatment system. Although uncommon, the Woodford Formation flowback water is managed under permit through the Oklahoma Corporation Commission to allow for some disposal by land application (DOE 2009).

4.11.1 Residual Oil Zones: Unconventional Target

Primary and secondary oil production has oil saturations in conventional reservoirs starting at typically over 50%. An oil deposit that has notable oil shows in cores and cuttings and even in drill stem tests (DSTs) but has a starting natural oil saturation of 20–25% has not generally been an attractive exploration and production target. With the development of horizontal drilling and hydraulic fracture stimulation methods, residual oil zones (ROZs) have started to be an attractive target as a source of unconventionally produced oil and gas (see Figure 4.40).

A transition zone between an oil‐bearing zone and the underlying water zone has been referred to as the oil–water contact. Under certain conditions, a thick ROZ may exist below the transition zone (Melzer 2006). The San Andres Formation in the Permian Basin in west Texas contains ROZs. ROZs may be caused when regional uplift or tilting allows oil to migrate updip into new positions, leaving behind an ROZ. If no associated primary production exists, it is considered a “green fields” ROZ (Vance 2011). ROZs can also form beneath oil traps that have been breached by faults in areas of production. Although a partial oil trap is still present, the ROZ represents the area beneath the full trap that contains residual oil; these zones are called “brown fields” ROZs (Vance et al. 2011). Like enhanced conventional oil recovery, ROZs require carbon dioxide injection for production. Ultimately 90–100% of the injected carbon dioxide related to ROZ production is retained by the reservoir, which Vance (2011) aptly notes is a form of carbon sequestration. The low starting oil saturation of ROZs produces significant volumes of coproduced water, which requires reinjection, disposal, or water treatment.

4.11.2 Coproduced Water

In contrast to flowback fluids, coproduced water is naturally occurring water found in shale and tight sandstone formations that flows to the surface throughout the entire life span of the well. Coproduced water creates lower flow over a much longer period of time, typically from 2 to 40 barrel per day (bpd) as compared with the higher flowback water volumes. The coproduced water has high levels of TDS and leaches out minerals from the shale including barium, calcium, iron, and magnesium.

4.12.1 Transportation Challenges

Transmission of the produced natural gas relies primarily on pipelines. In areas without pipelines, natural gas can be reinjected or flared. Crude oil is transported by pipeline, tanker railcar, tanker trucks, and ships. Pipelines within production areas are called gathering lines that transport the natural gas such as natural gas plant liquids (NGPL) to processing facilities and crude oil to tank batteries. From there, the products are transported by feeder pipelines to the transmission pipelines. NGPLs include compounds such as liquefied petroleum gases: ethane, propane, butane, and pentane and isopentane. Once natural gas is moved along the pipeline system to the end user, distribution pipelines are used to move natural gas to residential, commercial, and industrial customers. The mode of distribution (pipelines, rail, highway, waterways) provides opportunities for accidents and spillage.

4.12.2 Lithium Source

Although treatment of the coproduced water is expensive and typically energy intensive, the brines could (for example) be a source of lithium used in electric vehicle (EV) batteries and other lithium‐ion batteries. Concentrations of lithium vary by region, depending on geology. Lithium concentrations in coproduced waters in the Marcellus Shale region of the Appalachian Basin are estimated at 80–200 milligrams per liter (mg l⁻¹). In 2014, the amount of produced water from the Marcellus Shale and Utica Shale of Pennsylvania was ~29 million barrels (109 777 m³). At 120 mg l⁻¹ lithium, the annual amount of lithium in the coproduced wastewater in Pennsylvania is about 545 metric tons. At a 50–60% recovery rate, the amount of lithium production from Pennsylvania wastewaters could reach 272–327 metric tons of lithium per year, respectively (Glazer et al. 2017).

4.12.3 Oil and Gas Production Limits

A procedure for calculating the estimated ultimate recoveries of Bakken and Three Forks Formations in horizontal wells in the Williston Basin has been developed (Cook 2013). In the full life cycle of an oil and gas field (Figure 4.41), as well as individual wells, an oil or gas well reaches its economic limit as the production rate does not cover the operating expenses, including taxes. Sometimes, reworking the oil or gas well can improve production. Other times, the injection of water, special fluids, or gases such as carbon dioxide or other petroleum engineering processes can enhance dwindling production rates to restore economic production. At some point, the economic limit for individual oil and gas wells is exceeded, and the wells must be properly abandoned.

Positive cash flow for oil and gas production can be maintained by (i) lowering operating costs or (ii) increasing production. Changing to more energy‐efficient and lower‐maintenance gas compressors could lower operating costs. Other cost‐saving measures include reusing and updating facilities and infrastructure. Increasing production can consist of the application of the following techniques:

• Optimizing artificial lift.
• Workover and stimulation of wells:
  • Acidizing stimulation.
  • Hydraulic fracture stimulation.
• Redrilling wells.
• Perforating new zones within existing wells.
• Infill drilling with new wells.
• Drilling horizontal wells.
• Controlling production limitations:
  • Water and sand control.
• New well completions.
• Enhanced oil and gas recovery methods.

The economic limit for oil and gas wells can be expressed using the following formulas (Table 4.12).

Economic limits	Description
Economic limit for oil
Economic limit for gas
Abbreviations	Definition
ELoil	The economic limit of an oil well in oil barrels per month (bbls month−1)
ELgas	The economic limit of a gas well in thousand standard cubic feet per month (MSCF month−1)
Poil	The current price of oil in dollars per barrel
Pgas	The current price of gas in dollars per MSCF
GOR	The gas/oil ratio as bbls/MSCF
LOE	The lease operating expenses in dollars per well per month
NRI	The net revenue interest, as a fraction
TAd	Ad valorem; Latin for “according to value” – a property tax, related to the value of the resource removed, fraction
Tgas	The gas severance taxes, production taxes, and all other taxes, as a fraction
Toil	The oil severance taxes, production taxes, and all other taxes, as a fraction
WI	The working interest, as a fraction. The WI owners must pay a corresponding percentage of the cost of leasing, drilling, producing, and operating a well or producing unit. After royalties are paid, the working interest also entitles its owner to share in oil and gas production revenues with other working interest owners, based on the percentage of the working interest owned
Y	The condensate yield as barrel/million standard cubic feet

4.15.1 Site Restoration

After production has occurred, site restoration following oil and gas exploration and production activities is regulated. Site restoration may include removal of all surface and shallow oil and gas equipment, as well as a plan for replanting and site restoration. Revegetation and land reclamation should include long‐term soil stabilization and erosion control. Local native plants that are diverse and robust should be used in the site restoration plan. The vegetation should be capable of self‐regeneration. A general drilling inspection checklist (see Table 4.14, Appendix I) provides highlights of the process. A checklist of various plans commonly developed for drilling operations may be required by local, state, or federal agencies (see Table 4.15, Appendix I). The prospect evaluation and hazard assessment checklist (see Table 4.16, Appendix I) shows a variety of special resource identification issues and special considerations. More detailed inspection forms are included in the specific chapters on environmental impacts. A simplified flow chart shows the seven phases of the exploration–production life cycle (Figure 4.39) described in this chapter.

References

1. Abdalla, C. and Drohan, J. (2010). Marcellus Education Fact Sheet: Water Withdrawals for Development of Marcellus Shale Gas in Pennsylvania. University Park: Penn State Cooperative Extension.
2. Al‐Mjeni, R., Arora, S., Cherukupalli, P. et al. (2011). Has time come for EOR? Oilfield Review 22 (4): 16–20.
3. Anderson, F.J. (2011). Potential Use of North Dakota Sand and Clay for Natural and Manufactured Proppants, North Dakota Geological Survey, Jan., 4 p. https://www.dmr.nd.gov/ndgs/documents/newsletter/jan.2011/Jan2011Proppants.pdf (accessed 20 October 2018).
4. Arthur, J.D., Bohm, B., Coughlin, B.J., and Layne, M. (2008). Hydraulic fracturing considerations for natural gas wells of the Marcellus shale. Presented at the Groundwater Protection Council (GWPC) Annual Forum in Cincinnati, OH (September).
5. Baker, R. (1979). A Primer of Oilwell Drilling, Fourth Edition, Petroleum Extension Service. Austin, TX: The University of Texas; 94 p.
6. Bateman, R. and Alzahabi, A. (2016). Use of well logging measurements and analysis for fracture design. In: Fracturing Horizontal Wells (ed. M.Y.Soliman and R.Dusterhoft), 379–398. New York: McGraw‐Hill Education.
7. Berg, R.R. (1986). Reservoir sandstones. Englewood Cliffs, NJ: Prentice‐Hall, 480 p.
8. Bureau of Land Management (BLM) (2014). Appendix P, Oil and Gas Operations, Colorado River Valley Field Office, Proposed RMP/Final EIS, February, 15 p.
9. Cook, T.A. (2013). Procedure for calculating estimated ultimate recoveries of Bakken and Three Forks Formations horizontal wells in the Williston Basin, U.S. Geological Survey Open‐File Report 2013–1109. Reston, VA: U.S. Department of the Interior, U.S. Geological Survey, 14 p. http://pubs.usgs.gov/of/2013/1109 accessed 20 October 2018.
10. Davies, R.J., Mathias, S.A., Moss, J. et al. (2012). Hydraulic fractures: how far can they go?Marine and Petroleum Geology 37: 1–6.
11. Dean, L. (2008). Reservoir Engineering for Geologists, Article 3: Volumetric Estimation, 11–14. Calgary, AB: Canadian Society of Petroleum Geologists (CSPG).
12. Elder, C.H. and Deul, M. (1974). Degasification of the Mary Lee coalbed near Oak Grove, Jefferson County, Alabama, by vertical borehole in advance of mining, U.S. Bureau of Mines Report of Investigations, vol. 7968. Pittsburgh, PA: U.S. Department of the Interior, Bureau of Mines, 21 p.
13. Ely, J.W. (ed.) (1985). Secondary recovery of oil, oil wells, hydraulic fracturing. In: Stimulation Engineering Handbook, ix, 357 p. Houston, TX: PennWell Books.
14. Energy & Environmental Research Center (EERC) (2016) A Review of Bakken Water Management Practices and Potential Outlook. Final Report, University of North Dakota, 2016‐EERC‐03‐11, March, 50 p.
15. Fisher, M. and Warpinski, N. (2012). Hydraulic fracture height growth: real data. Society of Petroleum Engineers Production and Operations 27: 8–19.
16. Glazer, Y.R., Lee, J.J., Davidson, F.T., and Webber, M.E. (2017). Shale boom could fuel batteries. Earth Magazine, American Geological Institute, Washington, DC (April), 15 p.
17. Groundwater Protection Council (2009). Modern Shale Gas Development in the United States: A Primer. Washington, DC: U.S. Department of Energy, Office of Fossil Energy.
18. Holden, T., Pendrel, J., Jenson, F., and Mesdag, P. (2013). Rock Properties for Success in Shales, CGG Internal White Paper #3035, January, 11 p. Houston, TX: CGG, GeoSoftware.
19. Jacob, H. (1989). Classification, structure, genesis, and practical important of natural solid bitumen (“migrabitumen”). International Journal of Coal Geology 11 (1): 65–79.
20. Kansas Geological Survey (KGS) (2001). Some Fundamentals of Geophysical Exploration, pp. 10–15. http://www.kgs.ku.edu/Publications/Oil/primer10.html (accessed 20 October 2018).
21. Kansas Geological Survey (KGS) (2017). Geological Log Analysis, Kerogen. Placed on website 24 March 2017; Retrieved 22 June 2018; http://www.kgs.ku.edu/Publications/Bulletins/LA/10_mudstones.html.
22. Keys, W.S. (1990). Borehole Geophysics Applied to Ground‐Water Investigations, U.S. Geological Survey Techniques of Water‐Resources Investigations, book. 2, chap. E2. Washington, DC: U.S. Department of the Interior, U.S. Geological Survey, 150 p.
23. King, G.E. (2009). Perforating Basics, How the Perforating Processes Work, 14 March 2009; GEK Engineering.
24. Lapham, W.W., Wilde, F.D., and Koterba, M.T. (1995). Ground‐Water Data‐Collection Protocols and Procedures for the National Water‐Quality Assessment Program: Selection, Installation, and Documentation of Wells, and Collection of Related Data, U.S. Geological Survey Open‐File Report, vol. 95‐398. Reston, VA: U.S. Department of the Interior, U.S. Geological Survey, 79 p.
25. Lapham, W.W., Wilde, F.D., and Koterba, M.T. (1997). Guidelines and Standard Procedures for Studies of Ground‐Water Quality: Selection and Installation of Wells, and Supporting Documentation, U.S. Geological Survey Water Resources Investigation Report 96‐4233, Reston, VA, USA, 119 p. https://www.nrc.gov/docs/ML1423/ML14237A642.pdf (accessed 20 October 2018).
26. Law, B.E. and Curtis, J.B. (2002). Introduction to unconventional petroleum systems. AAPG Bulletin 86: 1851–1852.
27. Law, B.E. and Spencer, C.W. (1993). Gas in tight reservoirs‐an emerging major source of energy. In: The Future of Energy Gases, US Geological Survey, Professional Paper, vol. 1570 (ed. D.G.Howell), 233–252. Washington, DC: USGS; US Government Printing Office.
28. Lehr, J.H. and Keeley, J. (eds.) (2016). Alternative Energy and Shale Gas Encyclopedia. Hoboken, NJ: Wiley, 912 p.
29. Levine, J.R. (1993). Coalification: the evolution of coal as a source rock and reservoir rock for oil and gas. In: Hydrocarbons from Coal, Studies in Geology #38 (ed. B.E.Law and D.M.Rice), 39–77. Tulsa, OK: AAPG.
30. Magoon, L.B. and Dow, W.G. (1994). The Petroleum System‐From Source to Trap, AAPG Memoirs. Tulsa, OK: American Association of Petroleum Geologists, 644 p.
31. McEwen, M. (2015). Significant San Andres play emerging amid ROZ fairways. Midland Reporter‐Telegram (20 June), 4 p.
32. Melzer, L.S. (2006). Stranded Oil in the Residual Oil Zone, Prepared for Advanced Resources International and the U.S. Department of Energy, Office of Fossil Energy, Office of Oil and Gas, February, 35 p.
33. Mian, M.A. (2011). Project Economics and Decision Analysis, 2e. Tulsa, OK: Pennwell Books, p. 482.
34. Neff, J.M., McKelvie, S., and Ayers, R.C., Jr. (2000). Environmental impacts of synthetic based drilling fluids. Report prepared for MMS by Robert Ayers & Associates, Inc. August 2000. U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, Louisiana, USA. OCS Study MMS 2000‐064. 118 pp. https://www.boem.gov/ESPIS/3/3175.pdf (accessed 20 October 2018).
35. OSHA (2014). Hydraulic Fracturing and Flowback Hazards Other than Respirable Silica, OSHA 3763012 2014. OSHA, Washington, DC, 27 p. https://www.osha.gov/Publications/OSHA3763.pdf: U.S. Department of Labor accessed 25 October 2018.
36. OSHA (2018). Oil and Gas Well Drilling and Servicing eTool. https://www.osha.gov/SLTC/etools/oilandgas (accessed 20 October 2018).
37. Patchen, D.G. and Carter, K.M. (eds.) (2015). A geologic play book for Utica Shale Appalachian basin exploration. Final report of the Utica Shale Appalachian basin exploration consortium, 187 p. http://www.wvgs.wvnet.edu/utica (accessed 11 October 2017).
38. Penn State Extension (PSE) (2011). Marcellus Shale Wastewater Issues in Pennsylvania—Current and Emerging Treatment and Disposal Technologies, Penn State University College of Agricultural Sciences.
39. Pollastro, R.M., Roberts, L.N.R., and Cook, T.A. (2013). Geologic assessment of technically recoverable oil in the Devonian and Mississippian Bakken Formation, chap. 5 of U.S. Geological Survey Williston Basin Province Assessment Team, Assessment of undiscovered oil and gas resources of the Williston Basin Province of North Dakota, Montana, and South Dakota, 2010 (ver. 1.1, November 2013): U.S. Geological Survey Digital Data Series DDS–69–W, 34 p.
40. Rice, D.D. (1993). Composition and origins of coalbed gas. In: Hydrocarbons from Coal, AAPG Studies in Geology, vol. 38 (ed. B.E.Law and D.D.Rice), 159–184. Tulsa, OK: The American Association of Petroleum Geologists.
41. Rogers, D., Fout, G., and Piper, W.A. (2006). New innovative process allows drilling without pits in New Mexico. The 13th International Petroleum Environmental Conference, San Antonio, TX (17–20 October).
42. Rogers, D., Smith, D., Fout, G., and Marchbanks, W. (2006). Closed‐loop drilling system: a viable alternative to reserve waste pits. World Oil 227 (12).
43. Sharif, A. (2007). Tight gas resources in Western Australia, Western Australia Department of Mines and Petroleum, September, as quoted in Wikipedia.org, Tight Gas; Retrieved 11 October 2017.
44. Tissut, B. P., and Welte, D.H.,(1984). Petroleum Formation and Occurence, Second edition, Springer‐Verlag, Berlin, 699 p.
45. US Geological Survey (USGS) (2013). Petroleum Resource Assessment of the Bakken and Three Forks Formations, Williston Basin Province, Montana, North Dakota, and South Dakota.
46. US Department of Energy (US DOE) (2007). Development of Radar Navigation and Radio Data Transmission for Microhole Coiled Tubing Bottomhole Assemblies. Washington, DC: United States Department of Energy; DE‐FC26‐03NT15477.
47. US Department of Energy (US DOE) (2009). Modern Shale Gas Development in the United States: A Primer. Washington, DC: US DOE, Office of Fossil Energy, National Energy Technology Laboratory, 100 p.
48. US Department of Energy (US DOE) (2013a). Modern Shale Gas Development in the United States: A Primer. Washington, DC: US DOE, Office of Fossil Energy, National Energy Technology Laboratory, September, Modern Shale Gas Development in the United States: An Update; 79 p.
49. US Department of Energy (US DOE) (2013b). National Energy Technology Laboratory, E&P Focus, Fall, Oil & Natural Gas Program Newsletter, 16 p.
50. US Department of Energy (US DOE) (2014). Enhanced Oil Recovery. https://www.energy.gov/fe/science‐innovation/oil‐gas‐research/enhanced‐oil‐recovery (accessed 20 October 2018).
51. US Energy Information Administration (US EIA) (2013). EIA/ARI World Shale Gas and Shale Oil Resource Assessment Technically Recoverable Shale Gas and Shale Oil Resources: An Assessment of 137 Shale. Prepared for US EIA and US Department of Energy, Prepared by Advanced Resources International, Inc., 707 p.
52. US Energy Information Administration (US EIA) (2017). Utica Shale Play, Geology Review, April, 18 p.
53. US Environmental Protection Agency (US EPA) (2004a). Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs, June, Chapter 4, Hydraulic Fracturing Fluids, EPA 816‐R‐04‐003. Washington, DC: U.S. Environmental Protection Agency, 26 p.
54. US Environmental Protection Agency (US EPA) (2004b). Evaluation of Impacts to Underground Sources June 2004 of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs, Final June, EPA 816‐R‐04‐003. Washington, DC: US EPA, 463 p.
55. US Environmental Protection Agency (US EPA) (2015a). Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0 [EPA Report]. (EPA/601/R‐14/003). Washington, DC: Office of Research and Development, U.S. Environmental Protection Agency.
56. US Environmental Protection Agency (US EPA) (2015b). Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources [EPA Report]. (EPA/600/R‐15/047). Washington, DC: Office of Research and Development, U.S. Environmental Protection Agency. June, 599 p.
57. US Environmental Protection Agency (US EPA) (2015c). Review of Well Operator Files for Hydraulically Fractured Oil and Gas Production Wells: Well Design and Construction [EPA Report]. (EPA/601/R‐14/002). Washington, DC: U.S. Environmental Protection Agency, Office of Research and Development.
58. US Environmental Protection Agency (US EPA) (2015d). Case Study Analysis of the Impacts of Water Acquisition for Hydraulic Fracturing on Local Water Availability, EPA/600/R‐14/179, May 2015. Washington, DC: U.S. Environmental Protection Agency 215 p. www.epa.gov/fhstudy.
59. US Environmental Protection Agency (US EPA) (2016a). Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States. Washington, DC: Office of Research and Development, EPA‐600‐R‐16‐236Fa, December, 666 p.
60. US Environmental Protection Agency (US EPA) (2016b). Executive Summary ‐ Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States. Office of Research and Development, Washington, DC, EPA‐600‐R‐16‐236ES, Executive Summary, December, 50 p. https://www.epa.gov/sites/production/files/2016‐12/documents/hfdwa_executive_summary.pdf (accessed 20 October 2018).
61. USGS (1999). Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil‐Field Equipment: An Issue for the Energy Industry, U.S. Department of the Interior, U.S. Geological Survey; USGS Fact Sheet FS–142–99. Denver, CO: U.S. Geological Survey.
62. Vance, D. (2011). Residual Oil Zones, A Tale of CO2 Opportunities, American Association of Petroleum Geologists, AAPG Explorer, 3 p.
63. Vance, D., Trentham, B., and Meltzer, S. (2011). Report on the Potential of Residual Oil Zones in the San Andres, 2011 CO2 Conference, presentation, 50 p.
64. Vengosh, A., Warner, N., Osborn, S., and Jackson, R. (2011). Elucidating Water Contamination by Fracturing Waters from Gas Wells: Integrating Isotopic and Geochemical Tracers, US EPA Workshop; Hydraulic Fracturing Workshop 1 – 28 pp. https://www.epa.gov/hfstudy/elucidating‐water‐contamination‐fracturing‐fluids‐and‐formation‐waters‐gas‐wells‐integrating (accessed 20 October 2018).
65. Warpinski, N. (2009). Microseismic Monitoring: Inside and Out. Society of Petroleum Engineers, Richardson, Texas, USA, SPE‐118537‐JPT. Journal of Petroleum Technology 61 (11): 6 p.
66. Warpinski, N., Du, J., and Zimmer, U. (2012). Measurements of hydraulic‐fracture‐induced seismicity in gas shales. SPE Production and Operations 27 (3): 240–252.
67. World Nuclear Association (2018). Naturally‐Occurring Radioactive Materials (NORM), May, 10 p. http://www.world‐nuclear.org/information‐library/safety‐and‐security/radiation‐and‐health/naturally‐occurring‐radioactive‐materials‐norm.aspx (accessed 20 October 2018).
68. Zou, C., Zhu, R., Tao, S. et al. (2013). Unconventional Petroleum Geology. Waltham, MA: Elsevier, 373 p.

Suggested Reading

1. Abdalla, C. and Drohan, J. (2009). Water withdrawals for development of Marcellus shale gas in Pennsylvania. University Park, PA: Penn State Extension, Penn State Extension., College of Agricultural Sciences.
2. Abdallah, W., Buckley, J.S., Carnegie, A. et al. (2007). Fundamentals of Wettability. Schlumberger Oilfield Review 19 (2): 44–61.
3. Advanced Resources International (2001). Federal lands analysis natural gas assessment, southern Wyoming and northwestern Colorado, Study Methodology and Results, DOE web site, May, 94 p. http://www.oilandgasbmps.org/docs/GEN35‐FederalLandsAnalysisNaturalGasAssessment.pdf (accessed 20 October 2018).
4. Arthur, J.D., Bohm, B., Coughlin, B.J., and Layne, M. (2009). Evaluating implications of hydraulic fracturing in shale gas reservoirs. SPE‐121038. Proceedings of the 2009 SPE Americas Environmental and Safety Conference, San Antonio, TX (23–25 March 2009). Richardson, TX: Society of Petroleum Engineers.
5. Bureau of Land Management (BLM) (1983). Onshore oil and gas order no. 1, Approval of operations on onshore Federal and Indian oil and gas lease. Final Rule: Federal Register/Vol. 48, no. 205, Friday, 21 October 1983.
6. Cenegy, L.M., McAfee, C.A., and Kalfayan, L.J. (2011). Field study of the physical and chemical factors affecting downhole scale deposition in the North Dakota Bakken Formation, SPE‐140977‐MS, 2011. SPE International Symposium on Oilfield Chemistry, The Woodlands, TX (11–13 April 2011).
7. Crafton, J.W. (1998). Well evaluation using early time post‐stimulation flowback data. Presented at the 1998 SPE Annual Technical Conference and Exhibition held in New Orleans, LA (27–30 September 1998), Society of Petroleum Engineers, SPE# 49223; pp. 599–607.
8. Cramer, D.D. (2008). Stimulating unconventional reservoirs: lessons learned, successful practices, areas for improvement. SPE Unconventional Reservoirs Conference, Keystone, CO. SPE‐114172, 218–236. Red Hook, NY: Curran Publishing Services.
9. Department of Oil and Gas and Geophysical Resources (DOGGR) (2014). Oil and Gas Monitoring Program (SB4 Environmental Impact Report). Sacramento, CA: California Department of Conservationhttp://www.conservation.ca.gov/dog/Pages/SB4_Final_EIR_TOC.aspx (accessed 20 October 2018.
10. Energy and Environmental Research Council (EERC) (2014). Completion Technologies, Bakken Decision Support System. University of North Dakota; 3 p.
11. Eshleman, K.N. and Elmore, A. (2013). Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland. Submitted to Maryland Department of the Environment, Baltimore, MD (13 February), p. 172.
12. Hayes, T. and Severin, B.F. (2012). Final Report to RPSEA; Barnett and Appalachian Shale Water Management and Reuse Technologies. Report No. 08122‐05. FINAL.1; Contract 0812205, 30 March, 125 p.
13. Iverson, W.P. (1995). Closure stress calculations in anisotropic formations. SPE 29598‐MS. Low Permeability Reservoirs Symposium, Denver, CO (19–22 March 1995), 14 p. Richardson, TX: Society of Petroleum Engineers.
14. Joshi, S. (2007). Horizontal and Multilateral Well Technology, Petroleum Engineering‐Upstream, Encyclopedia of Life Support Systems (EOLSS), 9 p. https://www.eolss.net/sample‐chapters/c08/e6‐193‐12.pdf (accessed 20 October 2018).
15. King, G.E. (2010). Thirty years of gas shale fracturing: what have we learned? SPE 133456. Presented at the 2010 SPE Annual Technical Meeting and Exhibition, Florence, Italy, 23–25 September, 39 p.
16. King, G.E. (2012). Hydraulic fracturing 101: what every representative, environmentalist, regulator, reporter, investor, university researcher, neighbor and engineer should know about estimating frac risk and improving frac performance in unconventional oil and gas wells, SPE 152596. SPE Hydraulic Fracturing Technology Conference, The Woodlands, TX (6–8 February), 80 p.
17. LeFever, J.A. (2005). North Dakota Middle Member Bakken Horizontal Play, Geologic Investigation, vol. 8. Bismarck, ND: North Dakota Geological Survey, 1 p.
18. LeFever, J.A., Martiniuk, C.D., Dancsok, E.F.R., and Mahnic, P.A. (1991). Petroleum potential of the middle member, Bakken Formation, Williston Basin. In: Proceedings of the Sixth International Williston Basin Symposium, Saskatchewan Geological Society, Special Publication, vol. 11 (ed. J.E.Christopher and F.Haidl), 76–94. Regina, VA: Saskatchewan Geological Society.
19. Leverson, A. (1967). Geology of Petroleum, 2e. San Francisco, CA: W.H. Freeman, 724 p.
20. Nordquist, J.W. (1953). Mississippian stratigraphy of northern Montana, 4th Annual Field Conference Guidebook, 68–82. Billings, MT: Geological Society.
21. Pitman, J.K., Price, L.C., and LeFever, J.A. (2001). Diagenesis, Fracture Development in the Bakken Fm., Williston Basin: Reservoir Quality in the Middle Member, U.S. Geological Survey Professional Paper, vol. 1653, 24 p. Denver, CO: U.S. Department of the Interior, U.S. Geological Surveyhttps://pubs.usgs.gov/pp/p1653/p1653.pdf (accessed 20 October 2018.
22. Powell, R.J., McCabe, M.A., Slabaugh, B.F. et al. (1999). Applications of a New, Efficient Hydraulic Fracturing System. SPE Production & Facilities 14 (2): 131–138.
23. Railroad Commission of Texas (RRC) (2014). Hydraulic Fracturing Frequently Asked Questions, 7 p.
24. US Bureau of Land Management (BLM) (2014). Colorado River Valley Field Office – Proposed RMP/Final EIS, February, 15 p.
25. US Department of Energy (US DOE) (1993). Drilling Sideways: A Review of Horizontal Well Technology and Its Domestic Application, DOE/EIA‐TR‐0565; Distribution Category UC‐950. Washington, DC: Energy Information Administration, Office of Oil and Gas, U.S. Department of Energy, 30 p.
26. US Energy Information Administration (US EIA) (1993). Drilling Sideways: A Review of Horizontal Well Technology and Its Domestic Application, DOE/EIA‐TR‐0565 Distribution Category UC‐950. Washington, DC: Energy Information Administration, Office of Oil and Gas, U.S. Department of Energy, 30 p.
27. US Energy Information Administration (US EIA) (2011). The Geology of Natural Gas Resources, 14 February, Today in Energy.
28. US Energy Information Administration (US EIA) (2015). U.S. remained world's largest producer of petroleum and natural gas in 2014, 7 April 2015.
29. US Environmental Protection Agency (US EPA) (1982). Assessment of Environmental Fate and Effects of Discharges from Offshore Oil and Gas Operators, WH‐553. Washington, DC: US Environmental Protection Agency, 451 p.
30. US Environmental Protection Agency (US EPA) (1985). Modeling Remedial Actions at Uncontrolled Hazardous Waste Sites, EPA/540–2‐85/001. Washington, DC: US Environmental Protection Agency.
31. US Environmental Protection Agency (US EPA) (1988). Corrective Action: Technologies and Applications. Cincinnati, OH: Office of Research and Development, Center for Environmental Research Information, 19–20 April 1988, Atlanta, GA.
32. US Environmental Protection Agency (US EPA) (1991a). Seminar on RCRA Corrective Action Stabilization Technologies, Technology Transfer. Washington, DC: Center for Environmental Research Information.
33. US Environmental Protection Agency (US EPA) (1991b). Stabilization Technologies for RCRA Corrective Actions Handbook, Office of Research and Development, EPA/625/6–91/026. Washington, DC: Center for Environmental Research Information.
34. US Environmental Protection Agency (US EPA) (1995). Crude Oil and Natural Gas Exploration and Production Wastes: Exemption from RCRA Subtitle C Regulation. Washington, DC: U.S. Environmental Protection Agency, Office of Solid Waste; EPA530‐K‐95‐003, 30 p.
35. US Environmental Protection Agency (US EPA) (2013a). Naturally‐Occurring Radiation: Overview, Updated: 28 February 2013.
36. US Environmental Protection Agency (US EPA) (2013b). Class II Wells: Oil and Gas Related Injection Wells (Class II).
37. Veil, J.A., Daly, J.M., and Johnson, N. (2000). DOE helps the EPA expedite offshore regulations for synthetic‐based mud. USDOE's Oil and Gas Environmental Research Program 5 (1): 1–4.
38. Warpinski, N.R. (1985). Measurement of width and pressure in propagating hydraulic fracture. Society of Petroleum Engineers Journal 25 (1): 46–54.
39. Warpinski, N.R., Branagan, P.T., Peterson, R.E., and Wolhart, S.L. (1998). An interpretation of MSite hydraulic fracture diagnostic results. Paper SPE 39950 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, CO (5–8 April).
40. Warpinski, N.R. and Smith, M.B. (1989). Rock mechanics and fracture geometry in recent advances in hydraulic fracturing. In: Recent Advances in Hydraulic Fracturing, SPE, Monograph, vol. 12 (ed. J.L.Gidley), 57–80. Richardson, TX: Henry L. Doherty Memorial Fund of AIME, Society of Petroleum Engineers.
41. Warpinski, N.R. and Teufel, L.W. (1987). Influence of Geologic Discontinuities on Hydraulic Fracture Propagation. Journal of Petroleum Technology 39: 209–220.
42. Warpinski, N.R. and Teufel, L.W. (1989). In Situ Stresses in Low‐Permeability, Nonmarine Rocks. Journal of Petroleum Technology 41: 405–414.
43. Williams, J.H. (2014). The Marcellus Shale Gas Play, Geology, Development, and Water‐Resource Impact Mitigation. Troy, NY: USGS, New York Water Science Center.