Notional Field Development Final Report - EBN

EBN 

Notional Field Development 

Final Report 

Submitted by: 

Halliburton 

November, 2011

EBN Notional Field Development Plan 

Table of Contents 

1 Project Identification ............................................................................................................................ 9 

2 Background Information ..................................................................................................................... 11 

2.1 Surface Constraints ..................................................................................................................... 11 

3 Technical Analysis ............................................................................................................................... 13 

3.1 Petrophysical Evaluation ............................................................................................................. 13 

3.2 Hydraulic Fracture Design ........................................................................................................... 28 

3.3 Production Forecasting ............................................................................................................... 40 

3.4 Well Test Conceptual Design ...................................................................................................... 62 

3.5 Well Design ................................................................................................................................. 80 

4 Surface & Environmental Impacts .................................................................................................... 121 

4.1 Project Description .................................................................................................................... 121 

4.2 Regulatory Framework .............................................................................................................. 126 

4.3 Comprehensive Water Management Planning ......................................................................... 143 

4.4 General Environmental and HSE Management ........................................................................ 175 

4.5 Well Pad Construction .............................................................................................................. 190 

4.6 Infrastructure ............................................................................................................................ 202 

4.7 Waste Management ................................................................................................................. 222 

4.8 Well Containment ..................................................................................................................... 234 

5 Summary and Recommendations ..................................................................................................... 238 

© 2011 Halliburton All Rights Reserved 

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Abbreviations 

Bcf billion standard cubic feet 

BHP Bottom hole flowing pressure 

bpm barrels per minute 

EUR estimated ultimate recovery 

GPa GigaPascal 

OGIP Original gas in place 

IPR inflow performance relationship 

LWD logging while drilling 

MMscf million standard cubic feet 

MPa MegaPascal 

MHF Massive hydraulic fracturing 

nD nanoDarcy 

nR nanoRadian 

NPV net present value 

PR Poisson ratio 

psi pounds per square inch 

RF recovery factor 

S Hmax maximum horizontal stress 

S hmin minimum horizontal stress 

scf standard cubic feet 

SRA stimulated reservoir area 

SRV stimulated reservoir volume 

Tcf trillion standard cubic feet (28320 mn m 3 ) 

TOC total organic content 

UCS unconfined compressive strength 

YM Young’s modulus 


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List of Figures 

Figure 1-1, Region Map ................................................................................................................................. 9 

Figure 3-1 KWK-01 Mudlogged Section of Posidonia (Upper Show) & Aalburg (Lower Show) Shales ....... 14 

Figure 3-2, Stress Calibration from Dipole Sonic on WWS-02 .................................................................... 15 

Figure 3-3, WWS-02 Stimlog Analysis - Best Fit Synthetic DTC-DTS ........................................................... 16 

Figure 3-4, Synthetic PHIN to DTC Relationship from OTL-01 .................................................................... 17 

Figure 3-5, Brittleness Index ....................................................................................................................... 18 

Figure 3-6, Posidonia Shalelog .................................................................................................................... 19 

Figure 3-7, Posidonia Stimlog...................................................................................................................... 21 

Figure 3-8, Aalburg Shalelog ....................................................................................................................... 22 

Figure 3-9, Dipmeter Structural Analysis – Posidonia ................................................................................. 24 

Figure 3-10, Dipmeter Structural Analysis – Aalburg .................................................................................. 25 

Figure 3-11, World Stress Map & Lower Jurassic Structure ........................................................................ 26 

Figure 3-13, Representative 3D Planar Fracture Geometry, Aalburg Shale ............................................... 32 

Figure 3-15, Representative 3D DFN Geometry, Posidonia Shale .............................................................. 34 

Figure 3-16, Map View of Fracture Network, Posidonia Shale ................................................................... 35 

Figure 3-18, Representative 3D DFN Geometry, Aalburg Shale ................................................................. 36 

Figure 3-19, Map View of Fracture Network, Aalburg Shale ...................................................................... 37 

Figure 3-21, KWK-01 ShaleLog Template .................................................................................................... 42 

Figure 3-22, Layer Cake Model Consisting of 35 One Meter Thick Layers.................................................. 43 

Figure 3-23, Planar Fracture Design for Posidonia Formation .................................................................... 44 

Figure 3-24, Planar Fracture Design within QuikLook Simulator ................................................................ 44 

Figure 3-25, Production Forecasts for Initial Four Scenarios ...................................................................... 46 

Figure 3-27, Cumulative Gas Produced Over 15 Years for First Four Scenarios ......................................... 46 

Figure 3-28, % Improved Cumulative Production Over Vertical Well Scenario .......................................... 47 

Figure 3-29, Production Forecasts for Scenarios with Varying Fracture Number ...................................... 47 

Figure 3-30, Decline Rates for Scenarios with Varying Fracture Number .................................................. 48 

Figure 3-33, Cumulative Production in 15 Years for Six Scenarios ............................................................. 52 

Figure 3-34, Decline Rates Over 15 Years for Six Scenarios ........................................................................ 53 

Figure 3-35, Comparison of Dual Porosity Model (Unmodified & Modified) vs. the Base Case ................ 54 

Figure 3-36, Shale Gas Modeling ................................................................................................................ 55 

Figure 3-37, Fracture Complexity Added to Simulate Complex Fractures with Fissures ............................ 55 

Figure 3-38, Fracture Complexity Added to Simulate a Complex Fracture Network ................................. 56 

Figure 3-39, Fracture Design Used to Model Discrete Fracture Network (DFN) ........................................ 56 

Figure 3-40, Cumulative Production Forecasts for Added Fracture Complexity ........................................ 57 

Figure 3-41, Decline Rates over 15 Years for Dual Porosity Model ............................................................ 58 

Figure 3-42, Cumulative Production Forecast for all Scenarios .................................................................. 59 

Figure 3-44, Typical Pressure Response from Fractured Well .................................................................... 67 

Figure 3-45, Predicted Test Rate ................................................................................................................. 68 

Figure 3-46, Predicted Flowing Bottom Hole Pressure ............................................................................... 68 

Figure 3-47, Estimated Flow and Shut-in Period ........................................................................................ 72 


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Figure 3-48, Estimated Build Up Time ........................................................................................................ 72 

Figure 3-49, Zone 8C "Sweet spot" ............................................................................................................. 80 

Figure 3-50, Hazard Map ............................................................................................................................. 80 

Figure 3-51, "GO" Areas and Initial Pad Locations ..................................................................................... 81 

Figure 3-52, Lateral Pad Placement and Well Design Criteria .................................................................... 82 

Figure 3-53, Preferred Well Design ............................................................................................................. 82 

Figure 3-54, "Fish Hook" Type Well Design ................................................................................................ 83 

Figure 3-55, Well Profile Variations ............................................................................................................ 83 

Figure 3-56, Well Profile ............................................................................................................................. 84 

Figure 3-57, Scenario 1 ............................................................................................................................... 85 




Figure 3-61, Scenario 1 3D View of Wells ................................................................................................... 87 

Figure 3-62, Scenario 1 - 1500m Laterals .................................................................................................... 87 






Figure 3-68, CWP Scenario #2 Results - 2500m Laterals ............................................................................ 90 





Figure 3-73, Scenario 3 3D View of the Wells ............................................................................................. 93 

Figure 3-74, Scenario 3 - 1500 to 2500m Laterals ...................................................................................... 94 






Figure 3-80, Scenario 4 - 1500 to 2500m Laterals ...................................................................................... 97 

Figure 3-81, Scenario 5 Hybrid .................................................................................................................... 98 

Figure 3-82, Scenario 5 Hybrid .................................................................................................................... 99 

Figure 3-83, Scenario 5 Hybrid Wells/Pads ............................................................................................... 100 

Figure 3-84, Scenario 5 Hybrid Well Inclination Distribution ................................................................... 101 

Figure 3-85, Scenario 5 Pads with 10/9/8 Wells (Yellow Names) ............................................................. 102 

Figure 3-86, Scenario 5 Pads with 7/6/5/4/3/2 Wells (Yellow Names) .................................................... 103 

3-87, Scenario 6 infill based on Scenario #5 base case ............................................................................. 104 

Figure 3-88, Scenario 6 Core Area based on Sc #5 Hybrid Infill case ........................................................ 105 


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Figure 3-89, Scenario 6 Core Area based on Sc #5 Hybrid Infill case ....................................................... 106 

Figure 3-90, Scenario 6 Core Area based on Sc #5 Hybrid Infill case ....................................................... 107 

Figure 3-91, Scenario 6 Core Area pad locations ...................................................................................... 108 

Figure 3-93, Ball Activated Sliding Sleeve Completion ............................................................................. 113 

Figure 3-94, - Hydra-Jet Assisted Fracturing Method ............................................................................... 115 

Figure 3-95, HP-ACT Method using Coiled Tubing .................................................................................... 116 

Figure 4-1. “Base Case” hypothetical location. ......................................................................................... 124 

Figure 4-2. Provisional Procedure ............................................................................................................. 128 

Figure 4-3. Surface water in the Netherlands ........................................................................................... 133 

Figure 4-4. Wetlands area ......................................................................................................................... 136 

Figure 4-5. Excavation equipment ............................................................................................................ 137 

Figure 4-7. Procedures and Permits without NCR .................................................................................... 141 

Figure 4-8. Fresh water impoundment used to store water for fracking ................................................. 143 

Figure 4-11. Surface water includes rivers and streams ........................................................................... 148 

Figure 4-12. Surface water in Noord-Brabant, including areas with water supply areas and discharge 

sewage water treatment installations. The pink colored circles indicate the capacity (Mm3/yr) of water 

discharged from each of these facilities ................................................................................................... 149 

Figure 4-13. Area of the De Dommel Water Board, including the location of WWTP facilities: 1) Boxtel 

WWTP, 5) Tilburg WWTP, 6) Eindhoven WWTP, 7) Hapert WWTP, 9) Biest-Houtakker WWTP, 10) Haaren 

WWTP, 11) Sint-Oedenrode WWTP .......................................................................................................... 151 

Figure 4-14. Waste water treatment plant ............................................................................................... 152 

Figure 4-32. Diagram of Injection Well ..................................................................................................... 172 

Figure 4-33. Truck hauling produced water to an off-site disposal facility .............................................. 174 

Figure 4-35. Diesel-fired generator ........................................................................................................... 178 

Figure 4-36. Noise barriers are constructed to limit noise levels during construction activities ............. 180 

Figure 4-38. Diesel-fired construction lighting trailer ............................................................................... 185 

Figure 4-39. Example risk contour (Source: Oranjewoud rapport "Onafhankelijk rapport 

schaliegaswinning in Nederland) .............................................................................................................. 187 

Figure 4-40. Example risk contour (Source: Oranjewoud rapport "Oranjewoud rapport schaliegaswinning 

in Nederland) ............................................................................................................................................ 188 

Figure 4-41. A typical production site in the Netherlands ........................................................................ 189 

Figure 4-42. Wellheads on multi-well pad site ......................................................................................... 192 

Figure 4-43. Representation of 3D seismic data ....................................................................................... 193 

Figure 4-44. Geotechnical soil boring ....................................................................................................... 194 

Figure 4-45. Typical Well Pad Design ........................................................................................................ 195 

Figure 4-46. Wellpad with impoundment ................................................................................................. 196 

Figure 4-47. Impoundment for storage of water ...................................................................................... 197 

Figure 4-48. Installation of liner system for impoundment ...................................................................... 197 

Figure 4-50. Impoundment with above-ground water pipelines along side of roadway ......................... 200 

Figure 4-51. Stored wellpad site with wellheads and produced water storage tanks ............................. 201 

Figure 4-52. Typical drilling rig .................................................................................................................. 203 


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Figure 4-53. Staging of equipment for fracing operation ......................................................................... 204 

Figure 4-54. Asphalt road constructed to access produced water tanks ................................................. 205 

Figure 4-55. Electrical substation .............................................................................................................. 206 

Figure 4-56. Gas gathering system ............................................................................................................ 206 

Figure 4-57. Typical gas processing facility ............................................................................................... 207 

Figure 4-58. Gas processing facility........................................................................................................... 209 

Figure 4-59. Metering station ................................................................................................................... 210 

Figure 4-60. Produced water tanks with secondary containment ........................................................... 211 

Figure 4-61. Skid-mounted compressor .................................................................................................... 212 

Figure 4-62. Metering station along transmission pipeline ...................................................................... 213 

Figure 4-63. Control room for monitoring of SCADA system.................................................................... 214 

Figure 4-64. Pipeline right-of-way during construction ............................................................................ 215 

Figure 4-65. Surveying the right-of-way ................................................................................................... 216 

Figure 4-66. Lowering of pipe into trench ................................................................................................ 217 

Figure 4-67. Equipment for boring on horizontal directional drilling (HDD) operations .......................... 218 

Figure 4-68. Restoration of pipeline right-of-way .................................................................................... 220 

Figure 4-69. Pigging inspection tool .......................................................................................................... 221 

Figure 4-70. Pig launchers ......................................................................................................................... 221 

Figure 4-71. Markers along pipeline right-of-way .................................................................................... 222 

Figure 4-72. Graph of fracing fluid composition ....................................................................................... 224 

Figure 4-74. Drilling pipe can become NORM contaminated ................................................................... 228 

Figure 4-75. Typical retention basin used for stormwater management ................................................. 230 

Figure 4-76. Silt fence used as an erosion and sediment control device.................................................. 232 

Figure 4-77. Spill response equipment ..................................................................................................... 233 

Figure 4-78, Diagram of well casing for horizontal well ........................................................................... 234 

Figure 4-79. Representation of drinking water tables in relation to shale gas drilling operations .......... 237 


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List of Tables 

Table 3-1, Fracture Modeling Results ......................................................................................................... 28 

Table 3-2, Fracture Model Inputs ............................................................................................................... 29 

Table 3-3, Treatment Schedule for Fracture Design ................................................................................... 30 

Table 3-4, Preliminary Planar Fracture Model Summary (σ 2 >> σ 3 , average for two fractures), Posidonia 

shale ............................................................................................................................................................ 31 

Table 3-5, Preliminary Planar Fracture Model Summary (σ 2 >> σ 3 , average for two fractures), Aalburg 

shale ............................................................................................................................................................ 31 

Table 3-6, Preliminary DFM Fracture Model Summary (σ 2 > σ 3 , average for two networks), Posidonia 

shale ............................................................................................................................................................ 33 

Table 3-9, Comparison Results for DFN and Planar Fracture Geometry (20/40-mesh RC proppant), 

Aalburg Shale .............................................................................................................................................. 38 

Table 3-10, Permeability Table ................................................................................................................... 40 

Table 3-12, Initial Four Scenarios Based on KWK-01 .................................................................................. 45 

Table 3-13, Production Forecast Results of Scenarios with Varying Fracture Number .............................. 48 

Table 3-17, Job Parameter Comparison on Methods ............................................................................... 119 

Table 3-18, Comparison Results................................................................................................................ 119 

Table 4-3. Information about WWTP ....................................................................................................... 153 

Table 4-4 Flowback Water Chemical Composition – usually collected from Day 1 through 30 after a 

hydraulic fracture event............................................................................................................................ 158 

Table 4-5. Produced Water Chemical Composition .................................................................................. 158 

Table 4-7. Relevant Emission Guidelines .................................................................................................. 176 

Table 4-10. Existing Levels of Lighting ...................................................................................................... 183 

Table 4-11. Sports Lighting Levels ............................................................................................................. 184 

Table 4-12. Public Lighting Levels ............................................................................................................. 184 

Table 4-13. Fracturing Fluid Additives, Main Compounds, and Common Uses ....................................... 225 


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1 Project Identification 

Halliburton is pleased to present the final report for the Notional Field Development Plan Shale Play 

Noord Brabant, Netherlands to EBN. In preparation for exploration efforts in the Lower Jurassic shale 

gas in the Boxtel exploration concession (Province of Noord Brabant), we investigated the possibilities of 

a commercial shale gas development in the area concerned as identified as Zone 8C (which is deemed to 

have representative characteristics - surface and subsurface - for the whole of the area of interest for 

shale developments). 

Figure 1-1, Region Map 

In order to facilitate the need for EBN to have a more general look at the area, we reviewed multiple 

scenarios some of which will be detailed in the report. The team consistently kept the final deliverable 

(which is below) in mind when producing this final report. In the following sections you will see how the 

team met the final deliverables in each of the sections while giving alternative scenarios to be evaluated 

in a potential next phase. 


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Deliverables 

• Petrophysical analysis (1 well) for fracture design*( A type of well that will be selected from a 

number of wells (≤5) that EBN will provide) 

• Fracture treatment and well test conceptual design 

• Scenario surface configurations 

• Conceptual completion design 

• Water and frac systems descriptions 

• High-level documentation of critical project risks 

• Recommendations for “next steps” 

During the project various team members made several field trips within the US, to gain knowledge of 

shale production in both the Eagle Ford and Marcellus shale plays. These field trips were intended to 

add value to EBN in their further exploration of shale plays in the Netherlands. 


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2 Background Information 

2.1 Surface Constraints 

The pro-active planning for and responsible management of the surface facilities are critical elements of 

a shale gas development program because they are the only visual signs of the development activities 

that agency personnel and the general public can see and serve as a “representation” of the planning 

and standard of care related to the subsurface work. 

It is imperative that the surface facilities be developed in a transparent, responsible manner. Although 

the extraction of these gas resources is primarily a subsurface activity, in the eyes of the public - the 

surface facilities serve as the only visual representation of development efforts. 

The standard of care required for the development of these surface facilities is high and they must be 

designed, constructed and maintained in such a manner that exceeds the minimum regulatory 

requirements and industry standards. They serve to preemptively demonstrate that EBN have 

addressed any stakeholder concerns. 

From an environmental perspective, there are a number of stakeholder concerns that must be 

considered in relation to the surface facilities including: 

• Water resources 

o Design of drilling plans and design of well bores to ensure there is no potential for the 

contamination of drinking water supplies 

o The procurement of source water for drilling and fracing operations so as to not impact 

the availability and production volumes required by other stakeholders 

o The storage, use (and re-use) and disposal of these waters so as to not adversely affect 

the sounding communities 

• Air quality 

o Addressing the air emissions produced by the equipment required to extract, process 

and transport the shale gas 

o Concerns for the potential for increased greenhouse gas (GHG) emissions 

• Ecological 

o Selecting locations that limit to the minimum the ecological impacts on the natural 

environment 

o Implementing plans and procedures that reduce the potential for erosion of the soils 

and natural landscape and pollute nearby water bodies 

• General environmental and health & safety 

o Minimizing the potential soil contamination as a result of the operations 

o Eliminating the potential increased human health or ecological risks 

o Managing the noise levels and lighting emissions so as to not adversely impact the 

surrounding communities 

• Quality of life 


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o 

o 

Development plans that address issues such damage to roadways, traffic congestion, 

work hours and increased population associated with construction, drilling and 

operational activities 

Design of facilities and landscaping so as to minimize visual impairment of the natural 

environment 

For the purposes of this notional / feasibility study, the scope of work (SOW) for the team assigned to 

identify the critical issues associated with the construction and operation of the surface facilities 

required to support responsible shale gas development within the Netherlands has prepared sections 

within this report to address the potential concerns associated with the following surface facilities: 

• Wellpad site 

• Impoundments used for the storage of water 

• Water supply pipeline infrastructure 

• Gas processing facilities 

• Gathering systems 

• Transmission pipelines and requisite support facilities (metering, compression stations) 

The identified potential constraints are addressed in Section 4 of this report. 


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3 Technical Analysis 

3.1 Petrophysical Evaluation 

3.1.1 G&G Analysis 

EBN’s formation evaluation goals were to obtain an independent evaluation of possible commercial 

shale gas and oil within the Jurassic aged Posidonia and Aalburg formations. Various types of formation 

information were made available to the Halliburton Consulting team that indicates the presence of 

kerogen rich organic shale within these two intervals. Our main goal was to quantify how good the 

resource potential is based on actual hydrocarbon in place and how well the individual shales could be 

fracture stimulated based on modeled mechanical properties. In addition, we wanted to mine all 

available sub-surface information for hints to hydrocarbon type, formation temperature and pressure, 

and any available formation structure and fault information. We therefore selected adjacent wells to 

provide this information. The main well chosen as the nearest offset to the proposed project area and 

having wireline data over the intervals of interest was the KWK-01. 


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3.1.2 Mudlog Analysis 

Figure 3-1 KWK-01 Mudlogged Section of Posidonia (Upper Show) & Aalburg (Lower Show) Shales 

The mudlog indicates an excellent gas show in the Posidonia between 1750 and 1850 meters. Sample is 

described as pyritic shale with some calite carbonate near base of the show section. The Aalburg Shale is 

also demonstrating a decent gas show while drilling between the depths of 2075 and 2250 meters but 

not near as high as the Posidonia. Mud weight was calculated to be equivalent to 9.6 lbs /gallon for both 

intervals. 


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3.1.3 Petrophysics 

First, a synthetic DTC & DTS mechanical rock properties model had to be developed on a well where EBN 

had dipole sonic data. This was performed on the deeper (Triassic) sections of the WWS-02 well. Next, 

the missing neutron data needed to be remedied by developing a DTC to synthetic neutron conversion 

by crossplot analysis across the same organic shales in the OTL-1 well. This was done and the final 

analysis performed across both the Posidonia & Aalburg Shales. 

3.1.3.1 Stress Calibration 

Figure 3-2, Stress Calibration from Dipole Sonic on WWS-02 

Eight separate crossplots determining relationships between measured compressional and shear 

velocities were analyzed. Obvious linear relationships were best fit to apparent crossplot porosity (PHIA) 

and neutron porosity (PHIN). These were the only relationships that met selection criteria for building 

synthetic DTC and DTS curves from triple combo data when no actual dipole sonic data is available. That 

selection criteria being that the three curves used agree within one standard deviation of the composite 

mean. 

The real and synthetic DTC & DTS curves were then tested in a Stimlog TM analysis of the WWS-02 well. 

The calculated interval was the deeper pay section of Triassic age below any of the target organic shales, 


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but the clay bound water porosity sections were very similar to the uphole organic shales we are 

interested in. These lower sections will be mostly mechanically analogous because clay bound water 

drives the majority of the mechanical properties in these types of shales. The synthetic curves 

demonstrated good fidelity to the measured velocities over all ranges of porosity and lithology. we do 

have a measured DTC across the organic shales of interest in the KWK-01 well that will also allow us to 

quality check our synthetically derived DTC & DTS in that well. 

Figure 3-3, WWS-02 Stimlog Analysis - Best Fit Synthetic DTC-DTS 

3.1.3.2 Synthetic Neutron Calibration 

The OTL-1 well had both a neutron & DTC available across the target zones, so that well was used to 

baseline the calibration function. This may sound unorthodox, but the neutron and DTC both primarily 

respond to all the water in any formation. The only place they might significantly diverge is in a partially 

geopressured gas interval where the gas would make the DTC read higher and the neutron lower. In the 

crossplot data below, it is easy to see that the central range of data is going to only support a synthetic 

neutron with an accuracy of +/- .03 which is roughly a 10% swing in either direction. This will manifest 

itself in a total porosity that is too high by the same amount before we correct for clay and calculate 

kerogen volume. 


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Figure 3-4, Synthetic PHIN to DTC Relationship from OTL-01 

The concept of Shale “Brittleness Index” is reviewed here for the reader. The concept of a relationship 

linking Young’s Modulus & Poisson’s Ratio for describing generated fracture complexity has been gaining 

industry acceptance for quite some time. It is another way to describe “soft” ductile rock vs. “hard” 

brittle rock and the type of exposed surface we can expect when we frac. The harder a rock is, the more 

fracture complexity is generated when its frac gradient is exceeded. This is particularly true when a low 

stress anisotropy (σ2~σ3) condition exists. Generally speaking, a rock’s brittleness index is driven most 

by total clay volume. The brittleness index is one of the primary output curves of the Shalelog analysis 

across the organic shales in this project. 


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Figure 3-5, Brittleness Index 


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3.1.3.3 Posidonia Shalelog 

Figure 3-6, Posidonia Shalelog 

The Posidonia Shalelog Analysis uses a Passey Delta LOG R technique (3’rd track from right) to calibrate 

a calculated TOC to actual core measurements (2’d track from right). Two separate calculations using 

RHOB & DTC compare very favorably suggesting that the primary hydrocarbon type here is oil or rich gas 


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condensate. If the fluid type is dry gas, we would see a higher Passey calculation of TOC from the sonic 

which would be more affected by a DTC “stretch” effect from gas attenuation. That doesn’t appear to be 

the case here. Using both Passey techniques, the TOC is ranging between 4 and 16 and is averaging at 

least 6 through the section of highest effective porosity. Using default isotherms and a mud weight 

equivalent pore pressure in the calculation, the program gives us 250-300 SCF/TON. No attempt is made 

here to convert that value to oil since we need to knowthe GOR. 

. We would describe the main Posidonia porosity interval as high clay and carbonate shale with at least 

some background silica matrix. This is very soft, ductile shale with a very low brittleness calculation. This 

compares favorably with very low brinnell hardness values measured from core. Calculated mechanical 

properties show an YM of 1-1.2 MM psi and PR of .28-.31 and that would immediately suggest very low 

fracture complexity. This low value of YM corresponds very well to lab measurements of dynamic 

Young’s Modulus from other well core data referenced by EBN geologists. The shape of the displayed 

“Fracture Width” (immediately to the right of the Brittleness Index) would imply that although soft, 

there are apparently no real barriers to frac height growth across the face of the higher effective 

porosity interval. 

3.1.3.4 Posidonia Stimlog 

The attached Posidonia Stimlog is another way to better graphically display the proposed shale pay 

mechanical properties. There appears to be at least a 500 psi difference in closure stress between the 

best effective shale porosity and the bounding clay shales above and below. Note that the closure stress 

gradient and fracture gradient are presented in units of psi/meter. Calculated formation pressure is +/- 

2700 psi (a 1.5 psi/meter gradient). 

Note that the synthetic DTC from the stress model overlays the measured DTC in this well. This gives us 

confidence in our calibration parameters for stress for the whole project. 


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Figure 3-7, Posidonia Stimlog 

Posidonia Interval Stimlog - Net pay, digital number output, closure stress gradient, frac gradient, and 

unconfined stress added to display. 


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3.1.3.5 Aalburg Shalelog 

Figure 3-8, Aalburg Shalelog 


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The Aalburg interval is much thicker with four organic rich intervals but virtually no effective porosity. 

Using all the same interpretation parameters as the Posidonia above, there is much lower TOC and 

much higher clay by volume. All four zones are slightly more brittle than the Posidonia, but only the 

zones between 2060-2110 and 2130-2200 had any mudlog show. 

3.1.4 Dipmeter Analysis 

Posidonia & Aalburg intervals were luckily covered by a fairly high quality dipmeter run in the KWK-01. 

Solid filled dip tadpoles demonstrate high confidence in dip calculations in both zones. The bottom of 

the interpreted higher porosity interval in the Posidonia is cut by a higher angle fault block “wedge” as 

annotated below. This may or may not be a sealed fault block and could pose screenout risk when 

interval is fracture stimulated. 

Looking at structural dip orientation in the main Posidonia porosity, the plane of maximum principle 

stress should be perpendicular to the structural dip direction. Horizontal frac azimuth would most likely 

be E-NE x W-SW at this location. It should be noted that that is 70 to 90 degrees different than what is 

documented by large regional stress map supplied by EBN. 

Due to complex deposition and subsequent geologic extension and inversion, there may be little link 

between actual current structure and expected stress field orientation. The current stress field 

orientation should be one of the primary objectives of any new vertical well evaluation across the 

Posidonia and Aalburg Shales. Be aware that the stress field could be quite different from place to place 

within a large development area and the optimal azimuthal placement of horizontal wells is critical for 

such a play. 

Too high of structural dip can impose mechanical conditions that are sub-optimal for horizontal well 

development. The formation dip of 4 to 5 degrees in the Posidonia is still within reality for at least 

moderate horizontal well lengths. 


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Figure 3-9, Dipmeter Structural Analysis – Posidonia 


24


Figure 3-10, Dipmeter Structural Analysis – Aalburg 


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3.1.5 The Aalburg interval is showing 10-16 degree dip and too high dip 

rates for even a moderate reach horizontal well. Regional Stress 

Figure 3-11, World Stress Map & Lower Jurassic Structure 

EBN supplied stress map has regional faults and Sh max generally oriented NW x SE. A typical horizontal 

well azimuth with expectations of transverse frac placement should then be drilled NE x SW. Care should 

be taken to actually analyze the local stress field with oriented dipole sonics and borehole image logs 

run in vertical pilot holes at different locations. There is some significant local twisting of major faults as 

mapped under the proposed project area. 

3.1.6 Petrophysical Summary & Recommendations 

Posidonia shale has excellent effective porosity even if we have to ultimately discount some of it. It has a 

good solid range of excellent TOC per foot which should translate into high hydrocarbon volume. We 

would call it gas condensate or high liquids productive shale until we have data to support otherwise. It 

is very ductile and soft. It will swallow proppant unless high conductivity designs are pumped using 

higher prop concentrations and larger size proppant. 

The obvious faulted wedge below the Posidonia zone in the KWK-01 confirms the presence of high 

energy tectonic activity that should propagate at least some kind of natural fractures or complex stress 


26


into the shale. Any analysis program should include multiple DFITs (diagnostic fracture injection tests) to 

confirm PDL (pressure dependent leakoff) behavior that would be caused by natural fractures. 

We suggest pilot wells be pursued across the proposed project area running all available geochemical 

and oriented stress logs and then correlate all measurements to full core measurements. Set casing on 

these wells with tubulars large enough to use the same wells for whip-stock horizontal utility in the near 

future. 

The two uppermost intervals of the Aalburg shale should be better evaluated with vertical well testing in 

the same program. It also has to have a structural dip less than 10 degrees in any particular area to be a 

viable horizontal target. 


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3.2 Hydraulic Fracture Design 

The objective of this study was to estimate preliminary transverse hydraulic fracture geometry in a 

horizontal wellbore for the Posidonia and Lower Aalburg shale gas formations. Both planar and discrete 

fracture networks solutions are presented. Two transverse fractures were modeled for each fracture 

stage. 

Results from the preliminary fracture modeling suggest: 

Table 3-1, Fracture Modeling Results 

Posidonia and Lower Aalburg* 

Rate (per transverse fracture), bpm / m3/min ~ 20 / 3.5 

Water Volumes (per transverse fracture), bbl / m3 ~ 1500 / 239 

Proppant Mass (per transverse fracture), lbm / kg ~ 247,500 / 112,264 

*Lower Aalburg was modeled with the recommended hydraulic fracture treatment schedule from the 

Posidonia. Rates, mass and volumes are consistent between the two formations but do result in 

different geometries. 

3.2.1 Fracture Modeling Scenarios 

Petrophysical data used for fracture model inputs were derived from the offset well KWK-01 and the 

experience with similar shale formations in North America (Eagle Ford Shale). The log derived rock 

properties for the Posidonia and Lower Aalburg (low Young’s Modulus and ductile) require larger mesh 

proppant for the required conductivity to maintain reservoir liquid hydrocarbon flow to the wellbore. 

Proppant embedment, proppant crushing, and formation fines migration, cycling, and gel damage result 

in a loss of conductivity. The Posidonia and Aalburg appear to be especially prone to proppant 

embedment (i.e., loss of fracture width) and traditional low concentrations of small-mesh proppant are 

unlikely to be as effective as a higher conductivity pack. Higher proppant concentrations 1 to 8 lbs/ft 2 

(120 to 960 kg/m 3 ) may be required. 

Fracture models inputs were run utilizing a permeability of 100 nD and total leakoff coefficient of 

C t= 0.0002 ft/min 1/2 (0.00610 cm/min 1/2 ). Closure pressure was estimated at 4760 psi (328.2 bar) for 

Posidonia and 5180 psi (357.1 bar) for Aalburg from log derived petrophysical analysis. Final fracture 

conductivity and fracture characteristics were determined using a defined fracture cutoff of 0.5 lbm/ft 2 

(2.44 kg/m 2 ). The fracture geometry may appear overdesigned, but the fracture models assumed a 

proppant pack damaged of 90% damage to account for conductivity loss (embedment, etc). There are 

multiple modeling options to address these problems but this methodology is a consistent modeling 

approach used in other North American shales. 

For comparative purposes of fracture conductivity, two different sizes of proppant were used: 20/40 and 

30/50-mesh, both Atlas Premium Resin Coated proppant. Halliburton fracturing fluid, Sirocco 30 

lb/Mgal was used as the fracturing fluid. Sirocco fluid provides high loading proppant transport 


28


capabilities, uses less base polymer resulting in much higher regained conductivity with low gel residue 

in the proppant pack. 

Table 3-2, Fracture Model Inputs is a summary of the inputs used for the fracture design modeling. 

Table 3-2, Fracture Model Inputs 

Casing: 

177.8 x 114.3 mm (7” 32.0 lb/ft x 4 ½”, 13.5 lb/ft) 

Perforations (Posidonia): 3100 m TVD (10,170 ft), 48 perfs w/10 mm (0.39”) 

Perforations (Aalburg): 3350 m TVD (10,990 ft), 48 perfs w/10 mm (0.39”) 

Permeability: 

100 nD 

Total Leakoff, Ct: 

0.00610 cm/min1/2 (0.0002 ft/min1/2) 

Min. Conc. for Fracture: 

2.44 kg/m2 (0.5 lbm/ft2) 

Fluid: 

Sirocco 30 lb/Mgal 

Proppant: 

20/40 RC (Atlas PRC), 30/50 RC (Atlas PRC) 

Stress Gradient*: 

0.105 bar/m (0.517 psi/ft) 

Closure Pressure (Posidonia): 

328.2 bar (4760 psi) 

Closure Pressure (Aalburg): 

357.1 bar (5180 psi) 

Fracture interaction 

Active 

DFN: Natural fracture spacing 

dy= dx= dz = 7.62 m (25 ft) 

DFN: Proppant distribution 

Uniform 

*The stress gradient was obtained honoring log derived mechanical properties. However, the stress 

values are lower than expected and lower that what is typically seen in other shale formations. These 

values need to be confirmed and updated after the DFIT and log analysis is completed on the vertical 

well. 

The recommended pumping schedule for both Planar and Discrete Fracture Modeling Scenarios is 

Table 3-3, Treatment Schedule for Fracture Design. The pad fluid is pumped during the first stage of the 

treatment to create initial fracture geometry. The pad is followed by eight sets of 20/40 or 30/50-mesh 

proppant slurry, helping to develop geometry, conductivity and fracture length. During these eight 

stages of the treatment, the proppant is staged up from 1 ppg (119.83 kg/m 3 ) to 8 ppg (958.61 kg/m 3 ). 

At the end of placing the slurry 17.413 m 3 of flush is pumped to clear tubulars of proppant. Each stage of 

the treatment is designed for an average slurry rate of 7.15 m 3 /min (45 bpm). Total liquid volume per 

stage is 477.34 m 3 (3000 bbls). Total proppant mass is 224,530 kg (495,000 lbs) per stage. This treatment 

creates a maximum surface treating pressure of 291 bar (4221 psi), assuming the current stress gradient 

of 0.105 bar/m (0.517 psi/ft). 


29


Table 3-3, Treatment Schedule for Fracture Design 

Stage 

Average 

Slurry 

Rate 

Liquid 

Volume 

Slurry 

Volume 

Total 

Slurry 

Volume 

Total 

Time 

No. (m³/min) (m³) (m³) (m³) (min) 

Fluid 

Type 

Prop 

Type 

Conc. 

From 

100 

kg/m3 

Conc.To 

100 

kg/m3 

Prop. 

Stage 

Mass 

1 7.1544 107.88 107.88 107.88 15.079 SIRC30 0000 0 0 0 

2 7.1544 11.356 11.892 119.78 16.742 SIRC30 A001 1.1983 1.1983 1360.8 

3 7.1544 22.712 24.855 144.63 20.216 SIRC30 A001 2.3965 2.3965 5443.1 

4 7.1544 34.069 38.89 183.52 25.652 SIRC30 A001 3.5948 3.5948 12247 

5 7.1544 45.425 53.997 237.52 33.199 SIRC30 A001 4.7931 4.7931 21772 

6 7.1544 56.781 70.175 307.69 43.007 SIRC30 A001 5.9913 5.9913 34019 

7 7.1544 68.137 87.424 395.12 55.227 SIRC30 A001 7.1896 7.1896 48988 

8 7.1544 68.137 90.638 485.76 67.896 SIRC30 A001 8.3878 8.3878 57153 

9 7.1544 45.425 62.569 548.32 76.641 SIRC30 A001 9.5861 9.5861 43545 

10 7.1544 17.413 17.413 565.74 79.075 SIRC30 A001 0 0 0 

Total Slurry Volume 565.74 (m³) 

Total Liquid Volume 477.34 (m³) 

Total Proppant Mass 2.2453e+05 (kg) 

kg 


30


3.2.2 Planar Geometry Modeling Scenario 

The Preliminary Planar Fracture Model Summaries for Posidonia and Aalburg with two sizes of proppant 

are shown in the 

Table 3-4, Preliminary Planar Fracture Model Summary (σ2>> σ3, average for two fractures), Posidonia 

shale and 

Table 3-5, Preliminary Planar Fracture Model Summary (σ2>> σ3, average for two fractures), Aalburg 

shale below. 

Table 3-4, Preliminary Planar Fracture Model Summary (σ 2 >> σ 3 , average for two fractures), Posidonia shale 

20/40-mesh RC proppant 


• Efficiency, h = 90% 


• DPnet = 47.5 bar (688 psi) 

• DPnet = 47.2 bar (684 psi) 

• hf = 41 m (134 ft) 

• hf = 38.5 m (126 ft) 

• xf create = 257.2 m (844 ft) 

• xf create = 264.1 m (867 ft) 

• xf prop = 171.7 m (563 ft) 

• xf prop = 174.98 m (574 ft) 

• wf prop = 0.7 cm (0.276 in) 

• wf prop = 0.66 cm (0.26 in) 

• kfwf = 121.8 mD-m (399.6 mD-ft) 

• kfwf = 59.7 mD-m (195.8 mD-ft) 

• CfD = 7902 

• CfD = 3411 

It can be seen from the table that comparing two different sizes of proppant 20/40 and 30/50, the 

fracture conductivity created with 20/40-mesh proppant is approximately double the fracture 

conductivity created with 30/50-mesh proppant with similar geometries. However, placing the larger 

mesh proppant needs to be evaluated in the final design. 

Table 3-5, Preliminary Planar Fracture Model Summary (σ 2 >> σ 3 , average for two fractures), Aalburg shale 





• DPnet = 88 bar (1278 psi) 

• DPnet = 87 bar (1262 psi) 

• hf = 30.8 m (101 ft) 

• hf = 30.8 m (101 ft) 

• xf create = 357.1 m (1172 ft) 

• xf create = 358.5 m (1176 ft) 

• xf prop = 228.4 m (749 ft) 

• xf prop = 228.6 m (750 ft) 

• wf prop = 0.16 cm (0.06 in) 

• wf prop = 0.15 cm (0.06 in) 

• kfwf = 25.97 mD-m (85.2 mD-ft) 

• kfwf = 12.6 mD-m (41.5 mD-ft) 

• CfD = 1137 

• CfD = 553 


31


Figure 3-12, Resulting Similar Planar Fracture Geometry for both 20/40 & 30/50 Fracture Treatments, Aalburg Shale 

Figure 3-13, Representative 3D Planar Fracture Geometry, Aalburg Shale 


32


3.2.3 Discrete Modeling Scenario 

Most conventional fracture treatments result in bi-wing fractures. However, some naturally fractured 

coal and shale formations have geomechanical properties that allow hydraulically induced discrete 

fractures to initiate, propagate and create complex fracture networks, modeled discretely. Discrete 

Fracture Network (DFN) modeling is based on a methodology similar to that presented by Warren and 

Root (1963) for dual porosity naturally fractured reservoirs and Meyer et. al (2010) in SPE 140514. The 

discrete fracture network may be composed of secondary fractures in all three principal planes. The 

discrete fractures created in the x-z (major axis) and y-z (minor axis) planes are vertical, while the 

induced fractures created in the x-y plane are horizontal. The spacing in the x-z, y-z, and x-y planes are 

∆ y , ∆ x , and ∆ z , respectively. The Preliminary Discrete Fracture Network Model Summary with two 

sizes of proppant is shown in 

Table 3-6, Preliminary DFM Fracture Model Summary (σ2> σ3, average for two networks), Posidonia 

shale below. 

Table 3-6, Preliminary DFM Fracture Model Summary (σ 2 > σ 3 , average for two networks), Posidonia shale 





• DPnet = 45.3 bar (657 psi) 

• DPnet = 45.7 bar (662 psi) 

• hf = 39 m (128 ft) 

• hf = 39 m (128 ft) 

• xf create = 205.2 m (673 ft) 

• xf create = 205.5 m (674 ft) 

• xf prop = 152.4 m (500 ft) 

• xf prop = 152.95 m (502 ft) 

• wf prop = 0.32 cm (0.12 in) 

• wf prop = 0.32 cm (0.12 in) 

• kfwf = 56.3 mD-m (184.7 mD-ft) 

• kfwf = 28.3 mD-m (92.8 mD-ft) 

• CfD = 7390 

• CfD = 3699 

• Network Width: ~35 m (~115 ft) 


With the Discrete Fracture Network the length of the single wing fracture remains the same for both 

sizes of proppant. The DFN geometry can be seen in Figure 3-14, Resulting Similar Discrete Fracture 

Model Geometry (20/40 & 30/50 Fracture Treatment), Posidonia Shale. 


33


Figure 3-14, Resulting Similar Discrete Fracture Model Geometry (20/40 & 30/50 Fracture Treatment), Posidonia Shale 

Figure 3-15, Representative 3D DFN Geometry, Posidonia Shale 


34


Figure 3-16, Map View of Fracture Network, Posidonia Shale 

Table 3-7, Preliminary DFN Fracture Model Summary (σ 2 > σ 3 , average for two networks), Aalburg Shale 




• DPnet = 95.2 bar (1380 psi) 

• hf = 23.4 m (77 ft) 

• xf create = 257 m (843 ft) 

• xf prop = 176.4 m (579 ft) 

• wf prop = 0.06 cm (0.03 in) 

• kfwf = 10.7 mD-m (35 mD-ft) 

• CfD = 1208 

• Network Width: 40 m (131 ft) 


• DPnet = 98.8 bar (1428 psi) 

• hf = 22.6 m (74 ft) 

• xf create = 285.7 m (937 ft) 

• xf prop = 182 m (597 ft) 

• wf prop = 0.05 cm (0.02 in) 

• kfwf = 4.4 mD-m (14.3 mD-ft) 

• CfD = 480 



35


Figure 3-17, Resulting similar Discrete Fracture Model Geometry for both 20/40 and 30/50 fracture treatments, Aalburg 

Shale 

Figure 3-18, Representative 3D DFN Geometry, Aalburg Shale 


36


Figure 3-19, Map View of Fracture Network, Aalburg Shale 


37


3.2.4 Hydraulic Fracture Summary and Recommendations 

Results presented here are the average of two transverse, conductive and producing fractures per stage 

in either the DFN or Planar modeling scenario. Although the created DFN lengths are shorter than the 

Planar model, the sum of propped dominate primary fractures created by the Discrete Fracture Network 

is similar to the propped single fracture created in the Planar models solution. Fracture width and fluid 

efficiency in the DFN model is less those solutions in the planar model because the same fluid volume is 

being used to create complex fracturing geometry. Comparison of Posidonia and Aalburg fracture 

geometries can be found in the 

Table 3-8, Comparison Results for DFN and Planar Fracture Geometry (20/40-mesh RC proppant), 

Posidonia Shale and Table 3-9, Comparison Results for DFN and Planar Fracture Geometry (20/40-mesh 

RC proppant), Aalburg Shale below. 

Table 3-8, Comparison Results for DFN and Planar Fracture Geometry (20/40-mesh RC proppant), Posidonia Shale 

Planar σ2>> σ3 

(average for two fractures) 


• DPnet = 47.5 bar (688 psi) 

• hf = 41 m (134 ft) 

• xf create = 257.2 m (844 ft) 

• xf prop = 172 m (563 ft) 

• wf prop = 0.7 cm (0.276 in) 

• kfwf = 121.8 mD-m (399.6 mD-ft) 

• CfD = 7902 

DFN σ2> σ3 

(average for two networks) 


• DPnet = 45.3 bar (657 psi) 

• hf = 39 m (128 ft) 

• xf create = 205.2 m (673 ft) 

• xf prop = 152 m (500 ft) 

• wf prop = 0.32 cm (0.12 in) 

• kfwf = 56.3 mD-m (184.7 mD-ft) 

• CfD = 7390 


Table 3-9, Comparison Results for DFN and Planar Fracture Geometry (20/40-mesh RC proppant), Aalburg Shale 

Planar σ2>> σ3 

(average for two fractures) 


• DPnet = 88 bar (1278 psi) 

• hf = 30.8 m (101 ft) 

• xf create = 357.1 m (1172 ft) 

• xf prop = 228.4 m (749 ft) 

• wf prop = 0.16 cm (0.06 in) 

• kfwf = 25.97 mD-m (85.2 mD-ft) 

• CfD = 1137 

DFN σ2> σ3 

(average for two networks) 


• DPnet = 95.2 bar (1380 psi) 

• hf = 23.4 m (77 ft) 

• xf create = 257 m (843 ft) 

• xf prop = 176.4 m (579 ft) 

• wf prop = 0.06 cm (0.03 in) 

• kfwf = 10.7 mD-m (35 mD-ft) 

• CfD = 1208 



38


Given this modeling data and the results from the production forecast, eleven fracture stages are 

recommended to create 22 transverse fractures. 

Preliminary fracture design recommendation for Posidonia and Aalburg shale formations (per stage): 

• The fracturing design is recommended for two target formations, Posidonia and Aalburg. 

• It is recommended that larger 20/40-mesh proppant be used, however this needs to be verified 

once the vertical test well is drilled and the fracture models are re-run with the vertical well 

data. 

• It is recommended the total clean volume of 477 m 3 (3000 bbls) per stage, for 11 stages. The 

fracture half-length will drain 150-200 meters for 400 m well spacing. Volumes above this 

become unrealistic and impractical. 

• For this given fluid volume per stage it can be expected that an average of 15% will return for 

recycling purposes. Usually the water flowback is less than that but it serves well for the current 

estimates in this report. 

• For Posidonia a total height of 41 m for Planar or 39 m for DFN geometry, and for Aalburg a total 

frac height of 31 m Planar or 23 m DFN would require 224,530 kg (495,000 lbs) of proppant. This 

will give the propped half-length Planar geometry fracture of 172 m or 152 m for DFN in 

Posidonia, and 228 m Planar or 176 m DFN in Aalburg. 

• The recommended pump rate - 7.15 m 3 /min per stage or 3.5 m 3 /min per transverse fracture. 

This may be adjusted based on the final completion method (i.e., plug and perf, coil tubing, etc.) 

• The recommended treatment creates an average surface treating pressure of 291 bar (4221 psi) 

assuming the current stress gradient, which should be used for tubular design and wellhead 

considerations. Again, this needs to be verified with an updated data from the vertical well test. 

There is no more point in refining the recommended model until more information becomes available. 

Several other key diagnostic tests are suggested to increase the chance of a successful completion 

including DFIT (Diagnostic Fracture Injection Tests) tests and pre-treatment mini-fracs to adjust design if 

needed, along with contingency plans during the main treatment. 


39


3.3 Production Forecasting 

3.3.1 Production Forecasting Overview and Assumptions 

The objective of these simulations is to quantify the benefit of different well configurations and its 

associated completion. These consist of horizontal wells with a varying number of hydraulic fractures 

along its horizontal section. 

The model is based on a “layer cake model” that adheres to the rock properties interpreted by 

petrophysical evaluation. Within this reservoir model, different scenarios are simulated by certain 

factors such as permeability, horizontal length, and number of fractures along the wellbore. 

The following items are the list of assumptions for production forecasting: 

• Properties are continuous in each layer 

• Permeability values from 

• Table 3-10, Permeability Table 

• Dry Gas Simulation - No Adsorption 

• Area used in the simulation 

• Assumed PVT 

• Gas specific Gravity = .65 

• Gas Viscosity and Z factor was calculated by correlation 

• Gas Formation Volume Factor was calculated using the Z factor 

• Gas Z Factor was calculated by correlation using Yarborough and Hall 

• Fracture Complexity was approximated using a Dual Porosity Model 

Table 3-10, Permeability Table 

Permeability 

kx (mD) ky (mD) kz (mD) 

Initial Scenarios 0.005 0.005 0.0005 

Final Scenarios 0.0001 0.0001 0.00001 


40


Figure 3-20, Assumed PVT Plot 


41


3.3.2 Single Well Simulation 

To perform the single well simulations, the petrophysical interpretation from offset well KWK-01 was 

used for the initial model setup. 

Figure 3-21, KWK-01 ShaleLog Template below is a display of these interpretation results for the 

Posidonia formation. 

Figure 3-21, KWK-01 ShaleLog Template 


42


For the purpose of simulation, the Posidonia formation interval was divided into 35 layers where each 

layer represented 1m in thickness. Average values of porosity and water saturation were then extracted 

from the log data and assigned to their respective layers within the finite difference numerical simulator 

(QuikLook®). 

Figure 3-22, Layer Cake Model Consisting of 35 One Meter Thick Layers 

Fracture geometries were created by the hydraulic fracture specialist and used as an input into the 

simulation model. Figure 3-23, Planar Fracture Design for Posidonia Formation below is the planar 

fracture geometry used for the Posidonia Shale. 20/40 Mesh RC proppant was used to model hydraulic 

fractures. To account for embedment and loss of fracture propagation, these fractures were penalized 

as indicated by the fracture model design. 


43


Figure 3-23, Planar Fracture Design for Posidonia Formation 

Figure 3-24, Planar Fracture Design within QuikLook Simulator 


44


Table 3-11, Fracture Conductivity as Specified by 20/40 Mesh RC Proppant 

3.3.2.1 Initial Scenarios 

Initially, four scenarios were run in order to assess possible production scenarios and determine a base 

case for further simulation. The scenarios consisted of a vertical well with a bi-wing fracture, a 

horizontal well with a 1000 meter lateral and 15 associated bi-wing fractures, a horizontal well with a 

1500 meter lateral and 15 bi-wing fractures, and a horizontal well with a 1500 meter lateral and 30 biwing 

fractures. 

Table 3-12, Initial Four Scenarios Based on KWK-01 

Scenario 1 2 3 4 

Depth 1810 m 1810 m 1810 m 1810 m 

Lateral Length 0 m 1000 m 1500 m 1500 m 

Fractures 1 15 15 30 

The results of these scenarios are indicated in 

Figure 3-25, Production Forecasts for Initial Four Scenarios and Figure 3-26, Decline Rates for Initial Four 

Scenarios are below. 


45


180000 

160000 

140000 

1800m Posidonia_KWK 

Cumulative Gas (Mm 3 ) vs. Time (years) 

161031 Mm 3 

147842 Mm 3 

Cum Gas (10 3 m 3 ) 

120000 

100000 

80000 

60000 

40000 

38865 Mm 3 

109903 Mm 3 

Vertical 

3300 Horizontal - 15 Fracs 

5000ft Horizontal - 15 Fracs 

5000ft Horizontal - 30 Fracs 

20000 

0 

0.0 5.0 10.0 15.0 

Time (years) 

Figure 3-25, Production Forecasts for Initial Four Scenarios 

Figure 3-26, Decline Rates for Initial Four Scenarios 

Cumulative Gas (MCM) 

180000 

160000 

140000 

120000 

100000 

80000 

60000 

40000 

20000 

0 

Vertical 

1000m 

Horizontal 

15 Fracs 

1500m 

Horizontal 

15 Fracs 

1500m 

Horizontal 

30 Fracs 

Cumulative Gas (MCM) 

Figure 3-27, Cumulative Gas Produced Over 15 Years for First Four Scenarios 


46


% Increase from Vertical Case 

350.00% 

300.00% 

250.00% 

200.00% 

150.00% 

% Increase from 

Vertical Case 

100.00% 

50.00% 

0.00% 

1000m 

Horizontal 

15 Fracs 

1500m 

Horizontal 

15 Fracs 

1500m 

Horizontal 

30 Fracs 

Figure 3-28, % Improved Cumulative Production Over Vertical Well Scenario 

These preliminary results established that lateral length had a significant impact on production 

forecasts. Additional scenarios were run to account for the depth and reduced permeability of the 

Posidonia formation. Moreover, a scenario with 22 fractures (1 frac/stage) was simulated to determine 

if a relationship existed between the number of fractures and cumulative production. 

300,000 

3100m Posidonia 

Cumulative Gas (Mm3) vs. Time (years) 

Cum Gas (Mm3) 

250,000 

200,000 

150,000 

100,000 

245271 Mm3 

203418 Mm3 

147693 Mm3 

1500m Lateral - 15 Frac Stages 

50,000 


0 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 


Figure 3-29, Production Forecasts for Scenarios with Varying Fracture Number 


47


1000000 


Gas Rate (Mm3/day) vs. Time (years) 

Gas Rate (Mm3/day) 

100000 

10000 




1000 

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

Figure 3-30, Decline Rates for Scenarios with Varying Fracture Number 

Looking at Figure 3-29, Production Forecasts for Scenarios with Varying Fracture Number and Figure 

3-30, Decline Rates for Scenarios with Varying Fracture Number, it was concluded that fracture number 

did not have a significant impact on production as the rise in production between scenarios was linear in 

nature. As a result, the base case was agreed to be a horizontal well with a 1500 meter lateral and 22 

bi-wing fractures. 

Table 3-13, Production Forecast Results of Scenarios with Varying Fracture Number 

15 Frac Stages 22 Frac Stages 30 Frac Stages 

Cum Gas (MMscf) 5215 7184 8662 

Cum Gas (Mm3) 148 203 245 

Frac Spacing 

101.8 m/ 333.8 ft 

66.2 m/ 

217.1 ft 

46.5 m/ 

152.7 ft 


48


300000 

Frac Spacing (m) vs. Cumulative Gas (MCM) 

250000 

200000 

150000 

100000 

Cumulative Gas… 

50000 

0 

15 Frac Stages 

101.7m Frac Spacing 





Figure 3-31, Production Forecast Results of Scenarios with Varying Fracture Number 


49


3.3.2.2 Final Scenarios 

The agreed base case for production forecast scenarios was a 1500m lateral with 22 stages consisting of 

1 bi-wing fracture per stage (Figure 3-32, Areal Map Displaying Bi-wing Fractures for the Base Case). 

Permeability’s in the x and y direction were assigned a value of .0001mD and .00001 mD in the z 

directions as indicated in the assumptions. 

Table 3-14, Final Scenarios 

Lateral 

Length 

(m) 

No. of 

Fractures 

Perm (kx) 

(md) 

Perm (ky) 

(md) 

Perm (kz) 

(md) 

Comments 

Scenario 1 1500 22 0.0001 0.0001 0.00001 Base Case 

Scenario 2 1500 22 0.001 0.001 0.0001 

Base Case with Increased Permeability by a 

Factor of 10 

Scenario 3 1500 22 0.00001 0.00001 0.000001 

Base Case with Decreased Permeability by a 

Factor of 10 

Scenario 4 2500 36 0.0001 0.0001 0.00001 

Base Case with 2500m Lateral - 36 Fractures 

(equivalent frac spacing as Base Case) 

Scenario 5 1500 22 0.0001 0.0001 0.00001 

Base Case with a Discrete Fracture Network 

Model (DFN) – 

Complex Fracture Network 

Scenario 6 2500 36 0.001 0.001 0.0001 

Scenario 4 with Increased Permeability by a 

Factor of 10 

Scenario 7 2500 36 0.00001 0.00001 0.000001 

Scenario 4 with Decreased Permeability by a 

Factor of 10 

Scenario 8 1500 22 0.0001 0.0001 0.00001 

Base Case with a Discrete Fracture Network 

Model (DFN) - Fissures 

While five scenarios were requested by the client, an additional number of scenarios were simulated to 

provide additional value to our initial forecasts (highlighted as green in Table 3-14, Final Scenarios). 


50


Figure 3-32, Areal Map Displaying Bi-wing Fractures for the Base Case 

Figure 3-33, Cumulative Production in 15 Years for Six Scenarios, displays the production forecasts 

consisting of the base case of a 1500m lateral with 22 Fracture Stages and two scenarios where reservoir 

permeability is both increased and decreased by a factor of 10. Additionally, a scenario with a 2500m 

lateral is simulated using the same fracture spacing as the base case and a total of 36 fractures along the 

lateral. Two supplementary scenarios were simulated where reservoir permeability is both increased 

and decreased by a factor of 10 for the 2500m lateral scenario. 


51


700,000 


Cumulative Gas (MCM) vs. Time (years) 

Cum Gas (MCM) 

618706 MCM 

600,000 

500,000 

400,000 

300,000 

200,000 

100,000 

403496 MCM 

280380 MCM 

203419 MCM 

98324 MCM 

67127 MCM 

0 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

Figure 3-33, Cumulative Production in 15 Years for Six Scenarios 

BASE CASE: 

1500m Lateral - 


Base Case: 

Decreased Perm 

by Factor of 10 

Base Case: 

Increased Perm 


CASE A: 2500m 

Lateral - 36 Frac 

Stages 

Case A: 


by a Factor of 10 

Case A: 

Decreased Perm 

by a Factor of 10 


52


1000000 


Gas Rate (CMD) vs. Time (years) 

Gas Rate (CMD) 

100000 

10000 

BASE CASE: 1500m 

Lateral - 22 Frac Stages 

Base Case: Decreased 

Perm by Factor of 10 

Base Case: Increased 

Perm by Factor of 10 

1000 

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

Figure 3-34, Decline Rates Over 15 Years for Six Scenarios 


53


3.3.2.3 Fracture Complexity 

Fracture complexity was approximated by the use of a dual porosity model. Because the dual porosity 

model is fundamentally different from the homogenous (single porosity) case, an equivalent fracture 

permeability that mimics the homogenous case (without additional complexity) must be established. 

This was found to be .001mD rather than .0001mD used in the single porosity case. Fracture complexity 

is then introduced as an improved fracture permeability area around the hydraulic fracture with a 

permeability value of 0.15mD. 

Figure 3-35, Comparison of Dual Porosity Model (Unmodified & Modified) vs. the Base Case displays an 

approximately 53% loss in production using the base case parameters in a dual porosity model. By 

incorporating a fracture permeability of .001 mD we are able to closely imitate the single porosity 

homogeneous case. By reproducing the same cumulative production with a dual porosity model we can 

now accurately forecast how fracture complexity will affect our production. 

250,000 



200,000 

203419 MCM 



Cum Gas (MCM) 

150,000 

100,000 

200817 MCM 

CASE B: Dual Porosity 

Equivalent Modified 

Base Case: Dual Porosity 

Unmodified 

95424 MCM 

50,000 

0 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

Figure 3-35, Comparison of Dual Porosity Model (Unmodified & Modified) vs. the Base Case 

The Figure 3-36, Shale Gas Modeling, describes the different types of hydraulic fracture complexity we 

use in single well reservoir simulation. 


54


Figure 3-36, Shale Gas Modeling 

Previous scenarios were modeled by creating planar fractures in a ductile formation. In the attempt to 

add complexity to the system we modeled two different cases. One case assumes a complex fracture 

with fissure openings, as is indicative to the Woodford and Marcellus U.S. shale analogues. The other 

case assumes a complex fracture network which replicates how the Barnett Shale fractures in the 

subsurface. 

Figure 3-37, Fracture Complexity Added to Simulate Complex Fractures with Fissures and Figure 3-38, 

Fracture Complexity Added to Simulate a Complex Fracture Network display how complexity and 

fracture permeability is added to the model in both cases. 

Figure 3-37, Fracture Complexity Added to Simulate Complex Fractures with Fissures 


55


Figure 3-38, Fracture Complexity Added to Simulate a Complex Fracture Network 

Figure 3-39, Fracture Design Used to Model Discrete Fracture Network (DFN) below illustrates the 

fracture design used for modeling a discrete fracture network (DFN). Once again, this geometry is 

penalized as according to the hydraulic fracture design. 

Figure 3-39, Fracture Design Used to Model Discrete Fracture Network (DFN) 


56


The Figure 3-40, Cumulative Production Forecasts for Added Fracture Complexity shows the impact of 

increased fracture complexity within the reservoir simulation. 

350,000 



Cum Gas (MCM) 

300,000 

250,000 

200,000 

150,000 

100,000 

294816 MCM 

225361 MCM 

203419 MCM 



Case B: DFN - Complex 

Fracture Network 

Case B: DFN - Complex 

Fractures with Fissures 

50,000 

0 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

Figure 3-40, Cumulative Production Forecasts for Added Fracture Complexity 


57


1000000 


Gas Rate (CMD) vs. Time (years) 

Gas Rate (CMD) 

100000 

10000 

BASE CASE: 1500m Lateral - 


1000 

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

Figure 3-41, Decline Rates over 15 Years for Dual Porosity Model 

Because of increased fracture complexity, there is a more constant higher initial rate of production for 

the complex cases. After the initial depeletion of these fractures, decline rates become relatively 

identical over 15 years. 


58




Cum Gas (MCM) 

700,000 

600,000 

500,000 

400,000 

300,000 

200,000 

100,000 

0 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Time (years) 

BASE CASE: 

1500m Lateral - 


Base Case: 

Decreased 

Perm by Factor 

of 10 

Base Case: 



Case A: 2500m 

Lateral - 36 Frac 

Stages 

Figure 3-42, Cumulative Production Forecast for all Scenarios 

The Figure 3-42, Cumulative Production Forecast for all Scenarios illustrates the cumulative gas 

produced in a 15 year period with respect to all simulated scenarios. 


59


3.3.3 Summary and Recommendations 

It is concluded from these results that both permeability and lateral length have a significant impact on 

cumulative production. An increase in formation permeability by a factor of 10 will generate a 98% 

increase in production while an increased lateral length of 2500 meters will provide a 38% increase in 

production (from the base case). A decrease in formation permeability by a factor of 10 would decrease 

production by 67% from the base case. Increased lateral length in a low permeability scenario would 

provide a 46% increase in production, nevertheless a low 15 year cumulative production of 98324 MCM. 

Table 3-15, Cumulative Production for Final Scenarios 

Comments 

Cum Gas 

(MCM) 

% 

Increase/Decrease 

from Base Case 

Scenario 1 Base Case 203419 BASE 

Scenario 2 Base Case with Increased Permeability by a Factor of 10 403496 98.34% 

Scenario 3 Base Case with Decreased Permeability by a Factor of 10 67127 -67.00% 

Scenario 4 

Base Case with 2500m Lateral - 36 Fractures (equivalent frac spacing as 

Base Case) 280380 

37.83% 

Scenario 5 

Base Case with a Discrete Fracture Network Model (DFN) - Complex 

Fracture Network 294816 

44.92% 

Scenario 6 Scenario 4 with Increased Permeability by a Factor of 10 618706 204.13% 

Scenario 7 Scenario 4 with Decreased Permeability by a Factor of 10 98324 -51.67% 

Scenario 8 Base Case with a Discrete Fracture Network Model (DFN) - Fissures 225361 10.79% 


60


250.00% 

% Increase/ Decrease from Base Case 

200.00% 

150.00% 

100.00% 

50.00% 

% Increase/Decrease 

from Base Case 

0.00% 

1 2 3 4 5 6 7 8 

-50.00% 

-100.00% 

Figure 3-43, Layer Properties with Reduced Permeability Values 

Simulating complex fractures with fissure openings provide an 11% increase in production from the base 

case, while a complex fracture network similar to that of the Barnett provides a 45% increase in 

production from the base case. 

The petrophysical evaluation describes the Posidonia to be a ductile formation indicating that the most 

probable fracture geometry that is created would be planar. However, it is interesting to note that even 

in a complex fracture network scenario of the base case, the production forecast at the end of 15 years 

is closely equivalent to that of an extended lateral scenario of the base case, although initial cumulative 

production is lower. 

It is the recommendation of this report that accurate permeability measurements of the Posidonia 

formation are obtained to achieve a more likely production forecast. Once the first well is drilled and 

produced, permeability along with other reservoir properties can be better understood. Operationally, 

it is recommended that lateral length be extended as long as feasible taking into consideration 

environmental and mechanical constraints. 


61


3.4 Well Test Conceptual Design 

3.4.1 Introduction and Objectives 

The first well in the next drilling campaign will penetrate the Posidonia shale plays in the Noord Brabant 

field. There are still some uncertainties with regard to the fluid type and reservoir properties at this 

stage and much clearer definition will be expected as the evaluation progresses. The focus for this 

conceptual test design is on the shale prospect in the next drilling campaign. A more detailed test 

design will be generated at a later time once the reservoir and fluid parameters have been confirmed. 

The data and interpretation of the test in the first well will be utilized to improve the productivity and 

effectiveness of the fracturing jobs for the future wells. 

In addition, the first horizontal well will also provide information on the lateral variation in reservoir 

properties across the field. This also provides the chance to reduce the uncertainty in lateral changes in 

hydrocarbon richness of the formation. 

In general terms, there are a few objectives for the test and fluid sampling works. The main intention 

would be to get a better understanding of well deliverability, optimum drainage mechanism and key 

parameters to be used in future drilling and reservoir development within Noord Brabant or other 

similar reservoirs in the area. 

In this early stage of exploration well evaluation, a high level well test design is proposed to cover the 

uncertainty in both reservoir and fluid properties. The test objective will be updated at a later stage of 

the evaluation and is to include specific requirements that EBN might have. 

It is important that the specific well test objectives are documented and distributed to interested 

parties. This document will be a significant part of the final audit trail and, in the final analysis, will help 

in determining whether the objectives of the test have been achieved. 

Additional objectives, such as well productivity with respect to frac method, will be reviewed in order to 

seek ideas for improvement in the future unconventional reservoir development wells. 

The fluid properties evaluation is also an important goal to be achieved in order to help evaluate the 

requirements for achieving better completion design, surface facilities design and strategy to drain the 

reservoir. 

The overall conceptual test design is prepared within the context of the well test objectives. The 

appropriate testing equipment is included in the document based on the predicted fluid properties from 

the well so that the services can be mobilized in time for the operations. 

3.4.2 Well Test Requirements 


62


3.4.2.1 Well Test Data Requirements 

The main data and parameters to be collected: 

• Down-hole pressure and temperature data for the entire cycle of the well testing period (flow 

and buildup periods). The down-hole pressure and temperature data is to be collected from the 

down-hole pressure gauge. 

• Surface rate for oil, water and gas for vertical wells. For horizontal wells, additional flow rate 

measurements at each frac stage through production logging, fluid hold up and fluid capacitance 

is recommended. 

• Surface sample for gas reservoir; surface and bottom hole samples for oil reservoir. Monophasic 

sample is highly recommended whenever possible as this is the closest to representative 

reservoir fluid sample. Three sets of samples for each fluid type are recommended. 

• Surface pressure and temperature data during flowing and shut-in. 

• Impurities measurement during testing especially for H2S and CO2 content. 

• Heavy metal analysis (such as mercury) from reservoir fluid. 

• Pressure data during initial flow, subsequent flow and buildup periods. 

3.4.2.2 Well Test Procedures to be Performed 

The types of test procedures to be performed to achieve the objectives mentioned above are classified 

based on the type of produced fluid from the reservoir. The analysis summary is listed below. 

In general, the knowledge of the time required for stabilization is a very important factor in determining 

the type of test to be performed. In a gas well for example, liquid drop out is also to be considered in 

order to acquire good pressure data. 

Since the fluid to be produced is still part of the uncertainty in the next drilling campaign, the proposed 

analysis to be performed for both oil and gas are presented. 

The possible test methods for gas or oil wells for Noord Brabant field are listed below: 

Gas Wells 

Based on the information we have up to this point, the recommended test type for the Noord Brabant 

shale well will be FLOW AFTER FLOW. The consideration is mostly to achieve shorter test duration for a 

gas well with CGR of smaller than 8 bbl /MMscfd. 

The following criteria can be used to implement different test type options. 

FLOW AFTER FLOW - This test will be performed when the further evaluation shows that the reservoir 

produces moderate to high CGR gas from the produced fluid. It involves flowing the well on successively 

larger choke sizes one after another without shutting the well in. The well is flowed on each choke size 

until stabilized. Choke sizes are normally selected such that stabilization can be obtained relatively 


63


quickly and the duration of each flow period is normally the same. This test is terminated with a long 

final build up. 

ISOCHRONAL TEST - This test will be carried out when further evaluation indicates that the reservoir has 

fair to good permeability and not much fluid drop out is expected during testing. The test consists of a 

series of flow periods on successively larger choke sizes, each of equal duration. Each flow period is 

separated by a buildup of sufficient duration to reach stabilization. The final flow period is extended to 

achieve a stabilized flowing pressure for defining the IPR. The test is then terminated with a long 

buildup. 

MODIFIED ISOCHRONAL TEST - This test is recommended to be performed when further evaluation 

indicates that the reservoir has low permeability (tight) and not much fluid drop out is expected during 

testing or it is a dry gas situation. The test is similar to the isochronal test except that the final flow is 

extended until the well is stabilized. The final build up is often continued until the initial pressure at the 

start of the extended flow period is reached. 

Oil well 

Even though a single rate oil well test is sufficient, the Flow After Flow test is recommended and will be 

useful in generating the IPR curve for the reservoir in order to predict the reservoir performance as the 

reservoir pressure declines. 

If MDT data was taken in this well, the initial flow / shut in period might not be needed to determine the 

initial pressure. 

Reservoir parameters to be evaluated 

Well deliverability - Well deliverability analysis includes several parameters as mentioned in point a to f 

below. Flow rate measurement is normally done at the surface for a vertical well penetrating a single 

producing interval. For comingled production or horizontal wells with frac stages, a down-hole flow rate 

measurement using production logging is highly recommended to evaluate the performance of each 

perforation interval. 

In evaluating the well deliverability, the following parameters are normally evaluated or measured: 

a. Absolute Open flow potential 

b. Production behavior with wellbore pressure below bubble point (oil well) 

c. Rate dependent skin (gas wells) 

d. Water coning or gas coning effects (oil wells) 

e. Solids production tendencies 

f. Condensate drop out in the wellbore (gas condensate well) 

g. Reservoir permeability 

h. The permeability will be evaluated using a well model to be matched with the pressure response 

from the well test data. 


64


• For a more accurate permeability evaluation, it is recommended to carry out a pressure 

buildup with down-hole shut-in after a period of stable flow. 

• In the case of a hydraulically fractured horizontal well, the permeability calculated from 

a pressure match will be the average fracture permeability and we may not have a long 

enough shut-in period to get the system pressure (fracture+matrix). 

i. Reservoir pressure 

• Initial pressure can be determined from buildups following later flow periods. 

Alternately, it can be measured from an initial build up period after a short flow at the 

beginning of the test (MDT or RFT data). 

j. Reservoir boundaries 

• Boundaries may be sealing faults, permeability pinch outs, no flow boundaries or active 

pressure support boundaries in the form of mobile aquifers, or gas caps. 

• If verification of reservoir boundaries is a critical objective of the test, wire-line 

retrievable or surface readout gauges should be considered when designing the test 

string. 

k. Reservoir fluid sample 

• A representative reservoir fluid sample is recommended for PVT analysis which will be 

used in the calculation of hydrocarbon in place or fluid properties during reservoir 

modeling. 

• Solids produced during testing should be collected and evaluated. 

• The information on solids produced can be used for completion design, gravel packing, 

calculation of maximum production rate, surface facility design, artificial lift selection 

and design and generating a forecast for future well work activity requirements. 

l. Water sample 

• It is recommended to take water samples from water legs whenever possible to 

represent the possible future water production. For conventional reservoirs, this is very 

important to calibrate the Sw calculation and hence the hydrocarbon in place. 

• Water samples will also be necessary for facilities design, potential scaling problems and 

for analysis for environmental considerations. 

m. Fracturing interval contribution 

n. For horizontal or deviated wells with multiple frac stages, a PLT with radioactive type sensors is 

recommended to evaluate the flow contribution from each stage and frac performance. The 

advantage of using radioactive tools in horizontal or highly deviated wells is that the impact 

from well deviation is minimal. 


65


3.4.2.3 Analysis Methodology 

It is recommended to perform two types of well test analysis methods, an analytical method using 

homogeneous reservoir model assumptions and a numerical method using a reservoir simulator where 

detailed geological and petrophysical information is included in the model. 

Homogeneous model 

This model will be used to generate the reservoir parameters mentioned above based on homogeneous 

reservoir properties assumptions. Figure 3-44 shows a typical pressure response for a hypothetical gas 

well model in the shale play after fracturing job. 

It is seen from the plot that the information we will get from the test is mostly related to the fracture 

and not the matrix, unless we do a long term build test. 

On the natural fracture testing we will also see the response from matrix+fracture after the transition 

time indicated by a valley in the pressure derivative. 

The analysis to calculate fracture permeability will be by matching the simulated pressure to the 

pressure derivative in the mid time response of the pressure derivative data. 

The pressure derivative matched to the pressure derivative in the late time to calculate total 

permeability (fracture+matrix) could be performed should the long term buildup test be carried out. The 

late time response will be characterized by the second flat derivative after a valley following the early 

time response. 


66


Figure 3-44, Typical Pressure Response from Fractured Well 

The IPR curve using nodal analysis was matched to the flowing data to estimate the reservoir 

deliverability. Figure 3-45, Predicted Test Rate and Figure 3-46, Predicted Flowing Bottom Hole Pressure 

below show the expected range of values for the unconventional reservoir. These are typical values for a 

medium performance shale play reservoir in the US. Low productivity normally produces around 350- 

600 mscfd while the successful well produces up to 7 mmscfd. 


67


Figure 3-45, Predicted Test Rate 

Figure 3-46, Predicted Flowing Bottom Hole Pressure 


68


Single well reservoir model - In the case of a more detailed evaluation being required, a single well 

model using a reservoir simulation model can be generated. The advantage will be to include actual 

reservoir properties from the geological model. In this analysis, known boundaries from geological work 

such as faults and aquifers can be incorporated with better accuracy. 

Another advantage of a reservoir model approach is that we can provide a longer term production 

forecast for the well based on the geological and test data. The method is typically done to predict liquid 

drop in the reservoir or in the wellbore for high yield gas. 

Fluid analysis - There are a few types of analyses recommended for both reservoir evaluation and 

facilities design. 

Fluid analyses to be carried out at this stage are as follows: 

• Mercury content from sample 

• Gas / oil composition analysis 

• CVD (Constant Volume Depletion) analysis of the gas condensate or volatile oil sample to be 

used to simulate reservoir depletion performance and composition variation. This data will also 

be used to generate either black oil PVT or EOS correlation. 

• CCE (Constant Composition Expansion) analysis for the oil phase for similar purposes as in point 

2. 

The priority will be emphasized on the well deliverability (rate, permeability and skin). 

3.4.2.4 Test Equipment Requirements 

The equipment for the testing will be standard. The only thing that needs to be defined early is if sour 

service or HPHT equipment is required due to CO2/H2S content or high pressure/temperature condition 

of the reservoir. 

It is always the best option to have the down-hole and surface test equipment coming from the same 

company to eliminate problems with connections between surface and down-hole tools. In the case of 

the surface and test tools coming from different companies, early evaluations on required connections 

need to be done to allow time to manufacture some connections if required. 

Down-hole test equipment - The key tool for down-hole test equipment is the pressure gauge. A quartz 

gauge with sufficient battery capacity to hold data for the entire test period should be prepared. 

A downhole pressure gauge is be the best option since it will reduce the possibility that the wellbore 

storage effect continues into the middle and late time regions of the transient pressure response. This 

also will avoid misinterpretation of the permeability and boundary conditions. 


69


The data density or sampling per second should be set at the maximum capacity so that the gauge will 

hold for the entire testing period. Precautions will also be required in case the test runs longer than 

expected due to unexpected down times. The current test estimate of 4 days test time will require 

about 345,000 seconds of operations. The data density for pressure reading will be about 1 sample per 

second for a 400, 000 capacity quartz gauge. 

Surface test equipment - Standard surface testing equipment will be adequate unless CO2/H2S is 

expected to be present in significant amounts. There should be a local standard for this type of 

hazardous gas material produced to the surface. 

Here are some things to be considered for the surface test equipment: 

• As mentioned earlier, requirements for connection from down-hole to surface equipment needs 

to be prepared early on since it may require some manufacturing work for connectors. This is if 

the company providing the down-hole test is different than the one providing the surface test 

equipment. 

• An onsite H2S detector such as a Draeger tube will have to be available if H2S in the well stream 

fluid is a possibility. 

• All tests should incorporate the ESD (Emergency Shut-Down) system. The manual shutdown 

button should be located in a safe location away from the testing area. A typical location of ESD 

can be seen in the appendix. 

• All flow lines should be tied down or pinned. 

• The bubble hose or needle valve should be positioned downstream of the choke. 

• There should be no valve in the vent line. 

• Separators and surge tanks are fitted with two relief lines. 

• The hydrate formation should be evaluated to provide guidance on the maximum drawdown at 

the choke to avoid hydrate formation. 

• Need to confirm that the test tree can support the string weight especially when the surface and 

down-hole equipment are provided by different companies. 

• It is recommended to use the green burner with 98% efficiency or higher especially if oil or 

condensate is to be produced to the surface. 

3.4.2.5 Special Equipment Requirements 

Surface readout is optional during testing; however, it is recommended to use it for the following 

reasons: 

• Confirming that the valid data is collected into the memory gauge. Pressure leaks down-hole can 

cause invalid pressure buildup data. 

• Monitor the buildup real time to allow possible early buildup termination to save unnecessary 

operations cost. 


70


Once the expected fluid type for this field has been defined, swabbing equipment is recommended to be 

included in the case where the oil reservoir could not flow. 

3.4.3 Well Test and Fluid Sampling Design 

3.4.3.1 Vertical Well Testing 

Gas Well Testing 

Flow After Flow Test Summary (The rate guidance can be seen in Figure 3-45, Predicted Test Rate 

above.) 

• Perform clean up period until debris from wellbore disappears by observing the flowing well 

head pressure. 

• Flow the well at small choke until stabilized (4-6 hrs). Stabilization can be recognized by smaller 

fluctuations in well head flowing pressure around 5 psig and maximum of 10 psig if 5 psig can’t 

be achieved. As a reference, the expected rate will be between 350 MSCFD to 4-5 MMSCFD 

based on the shale gas well production in the US. 

• Flow the second rate by opening the choke until the flowing well head pressure is reduced by at 

least 100-500 psig (Pwf not to exceed 25% of the AOF value)and noticeable rate (gas rate >0.3 

mmcfd) difference is observed and then flow the well until stabilized (4-6 hrs). 

• Flow the third rate by increasing the choke again until the FTP is reduced an additional 100-500 

psig with noticeable flow rate difference (> .3 mmcfd) or more and keep flowing until stabilized 

(4-6 hrs). Normally the draw down is defined not to exceed 25% of the AOF value and comply 

with the frac design. 

Flow After Time Estimate 

• Clean up period 2-8 hrs 

• Flow after flow 12 hrs 

• Build up 18 hrs 

• Total testing time 30-40 hrs 

• For smooth operations, the total time required for testing usually between 3-4 days including 

the operations and sampling. 


71


Figure 3-47, Estimated Flow and Shut-in Period 

Figure 3-48, Estimated Build Up Time 


72


Additional step for high CGR gas or fractured reservoir is recommended to be implemented at the end of 

the test duration. 

• In the case that we discover a high CGR gas condensate reservoir, a longer flow period to 

monitor the evidence of increasing flowing bottom hole pressure may be needed. Depending on 

the CGR, this flow test can be up to one week before we can identify increasing flowing bottom 

hole pressure due to liquid dropping in the wellbore. This data can be used to design an 

appropriate completion to allow sustainable production. There might be a need to install a 

velocity string to lift up the liquid from bottom hole if the liquid dropping in the wellbore gets 

very high. 

• For evaluating the matrix properties of a fractured reservoir other than the shale play, a second 

or third pressure gauge is to be placed down-hole and retrieved at a later time after the long 

flow period. This is intended to monitor the reservoir pressure decline after a certain volume of 

production has been produced. This data will be used to predict the connected reservoir volume 

to the well and is related to the well potential cumulative production. This information is very 

useful in defining the well spacing requirement to effectively drain the reservoir. 

Oil Well Testing 

If MDT data was taken in this well, the initial buildup period might not be needed to determine the 

initial pressure. 

The basic steps recommended for the oil well are as follow: 

a. Initial flow period (10 minutes) 

b. Initial shut-in period (1 hr) 

c. First flow period 

d. Flow the well at small choke until stabilized (4-6 hrs). 

e. First buildup period 

f. Shut in the well. Use data from SRO as guidance to terminate the buildup or approximately 1.5 

times the flow period. 

g. Second flow period 

h. Open up the choke until the flowing tubing pressure reduces about 100 psi and noticeable flow 

rate (>50bopd) if possible and flow the stabilized rate for 4-6 hrs. 

i. Second buildup period 

j. Shut in the well. Use data from SRO as guidance to terminate the buildup or approximately 1.5 

times the flow period. 

k. Final flow period 

l. Open up the choke until the flowing tubing pressure reduces about another 100 psi with 

noticeable flow rate difference (>50bopd) and not to exceed 25% of the AOF value if possible 

and flow the stabilized rate for 4-6 hrs or longer depending on the allowed test times. 

m. Final buildup period 

n. Shut in the well. Use data from SRO as guidance to terminate the buildup or approximately 1.5 

times the flow period 


73


As far as equipment is concerned, additional equipment (pumps) or chemicals such as Nitrogen for 

lifting purposes should be prepared in the case that the oil could not flow to the surface. The choice 

between these techniques will depend on the availability and feasibility of the operation on location in 

case the drilling is conducted in a sensitive area . 

3.4.3.2 Horizontal Well Testing 

Similar test procedures can be applied to the horizontal well. However; in addition, a production log is 

recommended to be run for the following reasons: 

• More accurately determine the length of the contributing interval to be used in pressure buildup 

analysis for a more accurate kh value. 

• Provide the contributions from each fracturing stage along the horizontal section of the well. 

• Identify the stages which produce unwanted water production and appropriate remedial action 

can be taken. 

• Allow us to be able to evaluate the frac performance and make improvements on the future 

well. 

3.4.3.3 Special Considerations 

Special Topics 

Special topics on well test preparation are presented below in an effort to avoid unnecessary down time 

during test operation. 

Sour service equipment - Due to limited availability of sour service equipment, it will be helpful to 

predict the presence of CO2 / H2S from the wellbore fluid as early as possible. 

Green burner - Given that the drilling will not be very far from the community, a high efficiency burner 

(98% efficiency or higher) is required to reduce possibility for spills especially if the fluid will be oil or 

condensate. 

Stimulation techniques - If the case of a limestone reservoir is present as an additional target, matrix 

acidizing is recommended to be carried out as it will normally increase the productivity; otherwise, acid 

wash should be adequate to clean up wellbore and enhance near wellbore permeability. 

Test tubular - Due to the uncertainty whether it will be oil or gas testing, test tubular should have been 

prepared early on, especially if non standard tubing size is required and considered long lead. 

Two valve isolation - A minimum of two valve isolation is recommended below or at BOP. 

Zone isolation - It is recommended that the DST intervals be isolated from one another using bridge plug 

or cement retainers and cement. For a horizontal section with frac stages, a production log with array 

tool for resistivity and spinner along with radioactive density is run to determine the contribution from 

each frac interval. 


74


Recommended Practices 

Listed below are the recommended practices especially when the well location is not categorized as a 

remote area and very sensitive to environmental issues. 

• Tests should be kept as simple as possible whilst achieving the well test objectives. 

• Premium tubing connections (e.g. VAM connection, etc.) should be run for well tests that could 

potentially flow gas to the surface. It is highly recommended to have a two-valve isolation 

system below or at the BOP in every test string and, where possible, these barriers should be 

tested in the direction of flow. 

3.4.3.4 Fluid Sampling Recommended Procedure 

For all fluid samples, three sets of samples are recommended. 

Surface (Separator) Sampling 

Pressurized samples should be collected from the oil and gas lines on the separator once operating 

conditions have stabilized, i.e. when there are no random fluctuations in separator pressure, 

temperature, oil and gas rates and GOR. 

As a rule of thumb, on an oil test, a minimum of four times the capacity of the separator (40-50 bbl) 

should have been produced at stabilized conditions before proceeding with oil and gas sampling. The 

exception to this is during clean-up flows where stabilized conditions may not be achieved but a 

'back-up' sample is still required. 

Once stable flowing conditions have been achieved (refer to Section 5.2) 3 (three) sets of pressurized 

separator samples are to be taken (3 x oil, 6 x gas) with matched sets of one oil and two gas samples 

being sampled simultaneously. 

Dry Gas or Low CGR Gas 

Dry gas sampling is to be taken from the separator and no down-hole sample. The gas sample should be 

collected at the sample point on the gas flowline at the top of the separator. Sampling should be 

completed very slowly, taking up to a half an hour to fill one bottle to separator pressure. A detailed 

sample data sheet must be completed for each sample. 

Gas sample will be taken using 20 liter gas bottles which are supplied and evaluated. 

The gas sample should be collected at the sample point on the gas flowline at the top of the separator. 

Sampling should be completed very slowly, taking up to a half an hour to fill one bottle to separator 

pressure. A detailed sample data sheet must be completed for each sample. 


75


Oil 

Oil/condensate samples will be taken in supplied 600 cc pressurized conventional sample bottles. The 

sample bottle should be filled slowly, taking up to half an hour to complete. Details of the oil sample 

should be completed on the data sheet for the matching gas sample. A space must be allocated in the 

liquid sample bottles to allow for expansion effects during transportation. 

Ten (10) 5.0 gallon cans of oil are to be sampled from the oil line during the same period that the 

separator gas and oil samples are taken. It is essential that the drums or cans are filled only 3/4 full and 

the caps remain off for a sufficient period to allow light ends to flash off before replacing the cap. 

Water 

Samples of produced water are to be taken in 1 liter plastic/glass bottles during clean-up, at the start 

and end of the main flow, and at any time that a change in water production is noted. 

Four x 1 liter bottles of water, if sufficient is produced, are to be sampled from the water outlet of the 

separator during the final hour of the flow period. 

In the case of an aquifer test where the flow reaches the surface, collect 1 liter samples every 15 

minutes and measure the resistivity of the samples. When the resistivity becomes constant, collect 5 x 1 

liter samples. If the water needs to be reversed circulated from the tubing, this should be done slowly 

so that samples can be taken in the same manner as described for the natural flow case. For the aquifer 

test, the 2 x 1 liter plastic bottle samples are to be preserved by adding a biocide to lower the pH to 

about 2. 

Bottom Hole Sampling (Oil Zone Only) 

Bottom-hole sampling will be conducted during a stabilized flow period at rates which preclude bottomhole 

pressures from falling below bubble point pressure. The flow period for this sampling is 

discretionary and will be designated by the Well Testing Supervisor. 

After the tool string has been recovered, the sub-surface sampler should be heated and agitated prior to 

sample transfer to a Single Phase Sample bottle (SSB). Record the duration of heating prior to transfer. 

After sample transfer, each sampler should be washed with Carbon Disulfide, Tetra-hydrofuran or an 

aromatic solvent to collect any hydrocarbons left behind. The wash should be collected and properly 

labeled for cross reference to the corresponding SSB for transport to the lab. 

Choke Sampling 

Choke samples will be collected for the purpose of measuring the gravity of produced oil, resistivity of 

produced water and H 2 S & CO 2 content of produced gas. Samples should be collected per the sample 

program at various intervals during each of the DST flow periods. 


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3.4.4 Implementation Plan 

The implementation plan involves the following steps: 

• Final generation of the well test program when better knowledge of the fluid type and reservoir 

parameters becomes available. 

• Acquiring all the permits for explosives and long lead items such as casing or tubing for the test 

early. 

• Plan to have support materials such as Nitrogen and coiled tubing units near the well site for 

lifting oil well should the discovery be oil and could not flow. 

• Acquire all relevant environmental permits with regard to flaring related by the well test flow 

period. 

• Make sure that back up tools are available for down-hole tools which often require repair. 

• Make sure permits for the testing crew are current and completed prior to going to the location. 

3.4.5 Operational Command and Control 

The responsibilities of all personnel are listed below to make sure that the objective of the test can be 

achieved as planned. 

Drilling Superintendent - Responsible for transmitting orders to Drilling Supervisor on the rig. 

Amendments and additions to the testing program will be issued after consultation between relevant 

parties. 

Drilling Supervisor - Drilling Supervisor has an overall responsibility for the safety of personnel and 

operations during the test. He is responsible for the following tasks: 

• Make sure that all personnel on the rig have been briefed on their role during the test. 

• Make sure that all personnel directly involved in the test fully understand the program and what 

is required of them. 

• Make sure that the program is signed off on by the relevant management and that any changes 

to the program are confirmed in writing. 

• Make sure that all operations are carried out as per program and that items required to conduct 

the program are available and prepared for continuous operation throughout the test period. 

• During the testing program, he will delegate operational responsibility to the Test Engineer as 

appropriate. 

Well Test Engineer - The Test Engineer reports directly to the Drilling Supervisor on the rig. 

Responsibilities: 

• Make sure all equipment is available and incoming equipment is according to plan. 

• Carry out all operations in a safe and efficient manner as per well test program and make sure 

that any proposed changes to the program are authorized by the program signatories prior to 

implementation. 

• Annulus pressure is monitored at all times and it reads within operating parameters. 


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• Report the test progress to the Drilling Supervisor. 

• Transmit all well test information to the EBN or designated office at the stipulated times. 

• Ensure that all testing personnel have synchronized watches to the computer used for 

programming the downhole memory gauges. 

• Determine the flowrates (choke sizes) as per guidelines in the well test program. 

• Make sure that all relevant data is collected and checked for validity and quality. 

• Make sure that all samplings are carried out as per program. 

• Monitor the perforation job to be sure that they are at the correct depth. 

Reservoir Engineer - The Reservoir Engineer reports directly to the Drilling Supervisor on the rig and is 

responsible for data quality control and analysis of the test data. 

OIM and Toolpushers – Responsibilities include the following: 

• Make sure that radio silence, flaring and wind directions are advised to the relevant parties. 

• Stay informed as to changes in the well program. 

• Ensure that the Driller is at ALL times on the rig floor, or at relief periods, the Toolpusher is on 

the rig floor. Assistant Drillers will not be left alone on the rig floor. 

Drillers- Responsibilities include the following: 

• The Driller or Toolpusher will be on the floor at all times. 

• All operations concerning the annulus and any operation of rig manifold valves. 

• Monitoring of the annulus pressure at all times throughout the testing program. 

• Driller must inform all key personnel immediately of any problems on the floor. 

• The Driller will be in direct communication with the well testing personnel throughout the test 

and he is responsible for maintaining a watch on the test equipment and flowlines on the drill 

floor. 

• Be aware of the location of all personnel during the test. 

Well Test Supervisor - The Well Test Supervisor reports to the Test Engineer as the operator’s 

representative with the following responsibilities: 

• All operations of the test equipment. 

• All actions during the test are conducted safely and as per program. 

• Must inform the Test Engineer of any actions taking place with the well test equipment. 

• Make sure that all his crew understands their duties and how the test will be conducted. 

• Report any unusual occurrence IMMEDIATELY to Test Engineer. 

• The Well Test Crew only will be responsible for operating the surface test tree at all times. 

DST Specialists - The DST Specialist reports to the Test Engineer with the following responsibilities: 

• Operations of the down-hole DST Equipment. 

• Monitor annulus pressure at all times during the test. 


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• Check instrumentation on a regular basis. 

• Record all pump operations on the annulus, pressures and pump volumes and fluid bled off 

from annulus. 

• Must inform the Test Engineer prior to any actions taking place with the DST equipment. 

• All hazardous operations are conducted with the necessary permits. 

• Report any unusual occurrence to the Test Engineer IMMEDIATELY. 

Sampling Engineer - Responsibilities: 

• Make every effort that a representative sample is obtained. 

• Report to the Test Engineer of any doubts as to the validity of a particular sample. 

• Decisions made 

3.4.5.1 Decisions Made for Operations 

The decisions on the operations should be made according to the responsibilities outlined above at all 

times. Subsurface Manager will be consulted by the reservoir engineer during the operations. 


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3.5 Well Design 

3.5.1 Drilling Design – Central Zone 8C 

Zone 8C was centered on the major “Sweet spot” in the proposed acreage with arbitrary boundaries. 

Figure 3-49, Zone 8C "Sweet spot" 

A preliminary hazard map was created using a number of shape files provided, these included: Buildings, 

drill free zone drinking water, drinking water production areas, ecologically sensitive areas EHS, existing 

safety zones, groundwater protection areas, natura2000 areas, overhead power lines, railways, roads, 

surface water and underground gas pipe lines. In addition a shape file designating the open agricultural 

areas was provided but did not differentiate between agricultural areas used for greenhouse usage, 

cultivated fields or inner city parks and golf courses. The building file was also out of date with many 

areas seen in the satellite imagery as being built up as part of the urban expansion in the area. 

Figure 3-50, Hazard Map 


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The hazard map in Figure 3-50, Hazard Map was further enhanced using a combination of files to create 

a modified grid shown below. The left hand figure sows pink areas which represent the potential “GO” 

areas and 650 pad locations were created in these areas as displayed on the right. The 650 pads were 

then screened to provide some 323 Green “GO” Pads for further consideration and well planning. 

Figure 3-51, "GO" Areas and Initial Pad Locations 

3.5.1.1 Well and Lateral Design Parameters 

The well designs were based on the following criteria: Vertical well profiles to approximately 2100m 

with a 12°/30m build curve to the landing point at the beginning of the lateral. The laterals were spaced 

400m apart and had lengths of 1500m and 2500m. The distance between opposing lateral “Toes” was 

set at 200m, opposing “heels” at 300m. The maximum reach distance from the pad to the landing point 

was set at 800m. Two scenarios were planned using these lateral lengths as well as a third scenario 

utilizing variable lateral lengths between 1500m and 2500m to maximize reservoir contact between the 

major faults in the area. Laterals were constrained to a minimum distance of 100m to the faults. The 

objective of the first three scenarios was to maximize the lateral reservoir coverage with minimal regard 

to well design consistency. A fourth scenario was generated which leveraged the best configuration of 

pads resulting in a more consistent well design pattern commonly used in shale play development. 


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Figure 3-52, Lateral Pad Placement and Well Design Criteria 

3.5.1.2 Well Design Profiles 

The basis for the well design was explained previously but this assumes that a pad is placed at a certain 

distance from the heel to allow a vertical well to be drilled to the KOP at about 2100m and then build at 

12°/30m to the horizontal on an azimuth of 45° for 1500 or 2500m. 

Figure 3-53, Preferred Well Design 

The majority of the well profiles in the fourth scenario i.e.laterals generated around best pad locations 

with consistent well design are of this profile type. 

When the laterals are planned to maximize the reservoir contact, they are not perfectly aligned and fit in 

to the areas between the faults. This means the well profiles may vary from the one described to 

variations including “fish hook” or slant and turn wells. 


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Figure 3-54, "Fish Hook" Type Well Design 

In this case the well is kicking off at the required depth of approximately 2100m. The Figure 3-55 below 

shows some of the variation of well profiles created in the first three scenarios where the reservoir 

contact is maximized for field production. 

Figure 3-55, Well Profile Variations 

The well profiles can be modified by changing the planning scenario to allow for the wells to have a 

shallower KOP and low angle tangent sections down to the second KOP. So while appearing to be 

difficult wells to drill, they can be modified to take into account the offsets of the laterals to the pad 

locations. In this way the maximum amount of reservoir contact can be maintained whereas in the 


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scenario #4, the trade off is to reduce the number of pads and laterals to create the required well 

design, and thereby reducing the total productive area. 

Figure 3-56, Well Profile 

The primary development area (Core Area) is mixture of the well designs as shown in the Figure 3-56 

above with the kick off point (KOP’s) being between 1100 and 1150m. 

3.5.1.3 CWP Scenarios – Maximized Reservoir Contact 

CWP Scenario 1 – 783 x 1500m laterals were planned (1,174,500m) 


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Figure 3-57, Scenario 1 

212 Pads of the 323 pads were used to acquire 524 laterals 



85


259 laterals were outside the maximum 800m reach criteria. 


Laterals shown in yellow were not acquired either because they were outside the 800m reach criteria or 

due to the lack of a pad being available in the area. 



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Figure 3-61, Scenario 1 3D View of Wells 

CWP Scenario #1 Results are indicated in Figure 3-62, Scenario 1 - 1500m Laterals. 

Figure 3-62, Scenario 1 - 1500m Laterals 

The wells were planned in 100m reach increments from 200m to a maximum of 800m. Each result 

shows how many wells were created at each point. 

CWP Scenario 2 – 420 x 2500m Laterals were planned (1,050,000m) 


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138 Pads of the 323 pads were used to acquire 286 laterals 



88








89



CWP Scenario #2 results are indicated in Figure 3-68, CWP Scenario #2 Results - 2500m Laterals. 

Figure 3-68, CWP Scenario #2 Results - 2500m Laterals 



CWP Scenario 3 – 731 x (1500 to 2500m) laterals (Approx. 1,457,837m) 

This scenario was planned using a minimum of 1500m and a maximum of 2500m for the lateral length to 

maximize the reservoir coverage. 


90



184 Pads of the 323 pads were used to acquire 494 laterals. 



91







92



Figure 3-73, Scenario 3 3D View of the Wells 


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CWP Scenario #3 results are indicated in Figure 3-74, Scenario 3 - 1500 to 2500m Laterals. 

Figure 3-74, Scenario 3 - 1500 to 2500m Laterals 



CWP Scenario 4 - Optimized "Best Pad" Locations – 451 x (1500m – 2500m) laterals (Approx 945, 275m) 

This scenario was planned using a minimum of 1500m and a maximum of 2500m for the lateral length, 

to optimize the well design profile and the placement of the laterals around the pads. The majority of 

the well profiles in this scenario are vertical to the KOP as described previously under “Well and Lateral 

Design”. 



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83 Pads of the 323 pads were used to acquire 451 laterals. 





95



due to a lack of a pad being available in the area. 



96



CWP Scenario #4 results are indicated in Figure 3-80, Scenario 4 - 1500 to 2500m Laterals. 

Figure 3-80, Scenario 4 - 1500 to 2500m Laterals 




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CWP Scenario 5 – Hybrid Scenario 

Figure 3-81, Scenario 5 Hybrid 


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Figure 3-82, Scenario 5 Hybrid 


99


Figure 3-83, Scenario 5 Hybrid Wells/Pads 


100


Figure 3-84, Scenario 5 Hybrid Well Inclination Distribution 


101


Figure 3-85, Scenario 5 Pads with 10/9/8 Wells (Yellow Names) 


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Figure 3-86, Scenario 5 Pads with 7/6/5/4/3/2 Wells (Yellow Names) 


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3-87, Scenario 6 infill based on Scenario #5 base case 

Scenario #5 was re-worked to increase coverage in the area and reduce the number of exotic well 

designs to create the infill Scenario #6. 73 pads were increased to 80, with the 611 wells being 

increased to 637 giving a Total MD (m) of 3,458,844m with a new total lateral (m) of 1,234,168m. 69 

missed stubs were reduced to 42 and the total lateral lost (m) of 142,377m lost was reduced to 

86,284m. Some pads were replaced and a few wells re-assigned, new stubs were planned within the 

fault blocks. The overall change did not change the pad or well count but did change the lateral 

positions. The primary development area (Core Area) was extracted from this scenario. 


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Scenario 6 – Hybrid Design – Primary Development Area (Core Area) 

Figure 3-88, Scenario 6 Core Area based on Sc #5 Hybrid Infill case 

The primary development area or Core Area consists of 38 pad locations with 328 wells having a total of 

623,487m of reservoir lateral contact and a total drilling measured depth of 1,730,960m. The wells 

designs were a mix of the simple optimized and the more challenging higher reach types. 


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106




107


Pad Plan # 

Well Ct / 

Pad Northing-WH Easting-WH Pad Plan # 

Well Ct / 

Pad Northing-WH Easting-WH 

PPad 367 10 5705028 667553 PPad 390 8 5710617 665497 

PPad 333 10 5705363 657957 PPad 406 8 5712704 668726 

PPad 365 10 5705653 665787 PPad 392 8 5714440 664020 

PPad 347 10 5708059 661597 PPad 210 8 5720066 662313 

PPad 374 10 5708379 667051 PPad 137 8 5723231 655916 

PPad 382 10 5708577 663731 

PPad 592 10 5709454 653670 PPad 418 7 5707373 671102 

PPad 353 10 5710755 661171 PPad 429 7 5708303 671711 

PPad 436 10 5711882 671559 PPad 662 7 5713394 655988 

PPad 240 10 5712710 652748 PPad 229 7 5713578 658170 

PPad 227 10 5713821 660592 PPad 138 7 5721190 657607 

PPad 521 10 5715812 663837 

PPad 188 10 5717827 652109 PPad 279 6 5709587 657135 

PPad 199 10 5718086 656876 PPad 423 6 5710465 662847 

PPad 194 10 5718192 653647 PPad 548 6 5717152 659070 

PPad 191 10 5720233 653449 PPad 170 6 5719182 650296 

PPad 142 10 5726505 652170 PPad 128 6 5724830 653754 

PPad 294 9 5708719 655140 

PPad 434 9 5709902 667355 

PPad 269 9 5710623 658582 

PPad 233 9 5713791 654180 

PPad 132 9 5721906 651180 

PPad 129 9 5724084 653312 

Figure 3-91, Scenario 6 Core Area pad locations 


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3.5.1.4 Comparison of the Planning Scenarios 

Table 3-16, Planning Scenarios Comparison 

Maximized Reservoir Contact 

# of Stubs 

/Laterals 

Total Lateral 

(m) 

Scenario 1 - 

1500m 

Scenario 2 – 

2500m 

Scenario 3 - 1500m 

to2500m (mixed) 

Scenario 4 – 1500m 

to 2500m (mixed) 

Scenario 5 - Hybrid 

783 420 731 451 680 

1,174,537 1,050,020 1,457,837 945,275 1,178,578 

# of Pads 212 138 184 83 73 

# Wells / 

Laterals 

Total MD TD 

(m) 

# Stubs / 

Laterals 

missed 

Missed Lateral 

(m) 

524 286 494 426 611 

2,509,516 1,658,470 2,598,425 2,103,255 3,372,469 

259 134 237 25 69 

388,500 335,000 478,811 53,056 142,377 

Profile Type 

Multiple Well 

Profiles 

Multiple Well 

Profiles 

Multiple Well 

Profiles 

Standard Well 

Design 

Standard Well Design & 

Multiple Profiles Mixed 


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3.5.2 Completion Design 

3.5.2.1 Considerations for Completion Design 

The vast majority of shale development wells are multistage completions, comprising of an isolation 

method, which is used to separate each fracture interval and treatment, a perforation /fracture 

initiation method, and the fracture treatment (fluid and proppant). The primary isolation methods used 

in these wells are: open hole, cased and cemented, cased and uncemented isolation or sliding sleeves 

and packers. 

Cased and cemented horizontal completions offer a high degree of control of the fracture treatment 

placement, whereas open hole and uncemented annulus completions offer greater access to and have a 

better chance of stimulating a larger area within the interval. Uncemented completions use external 

mechanical and swellable casing packers to achieve zonal isolation. Swellable packers exert far less 

pressure on the formation than mechanical packers making them a better choice in less competent rock 

such as shale. The key differences between an unconventional shale well and a conventional well are in 

the completion design and stimulation methods that are applied. The objective in shale fracturing is to 

create a dense network of branch fractures, whereas fracturing in conventional reservoirs creates 

simple biwing fractures. 

Some shale reservoirs consist of individual laminated zones of < 1-ft thickness, that require pinpoint 

fracture placement, while others consist of thicker or massive shale beds that require a different 

method of fracture placement. Selection of the fracture initiation locations is largely based on TOC 

content and brittleness. 

Depending on the type of zonal isolation technique employed, a fracture staging method from one of 

the following groups is typically used: 

• Perf-and-Plug Processes 

• Sliding Sleeve Processes 

• Pinpoint Stimulation Processes 

3.5.2.2 Completion Processes Used Today 

Perf-and-Plug Process 

Wireline perf and plug method offers the ability to fracture stimulate multiple intervals where isolation 

between intervals is achieved using pumpdown plugs. The plug and perforate process can be applied in 

cased and cemented completions, and in cased completions using open hole packers. This technique 

involves running in the hole with conventional guns to perforate an interval, pulling out of the hole, 

pump the stimulation treatment, pump the plug to isolate the interval, and then run in the hole with 

guns to perforate the next interval. While there are many advantages when applying the plug and 

perforate process, such as that it is a simple process with economically acceptable results, there are 


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limitless numbers of stages, a higher-rate treatment schedule can be applied, and it is the most common 

method of multistage fracture stimulation. 

The process of pumping down the bridge plug and perforating guns is considered to be quite efficient 

and the overall operation can take from 2 to 4 hours between fracturing treatments depending on the 

well depth. 

Figure 3-92, Perf & Plug Fracturing Method 

Often however, the promise of efficiency for many of these high-rate, limited-entry perforating 

treatments provide elusive. Contingencies for early screen-out, gun miss-fires, premature setting of 

composite plugs, and tight spots in casing or even fishing operations for parted wireline dramatically 

impacted completion efficiency. To achieve limited-entry diversion high treatment rates were used 

which required a large amount of hydraulic horsepower onsite. 

For relatively thick, low stress, high brittle reservoirs like the Barnett Shale in North Texas the Perf & 

Plug method has been used extensively with satisfactory results. One point to mention is that this 

method requires the composite plugs be milled out at the end of the completion. When looking at 

horizontal well completions holistically the well intervention required to drill the plugs hurts the overall 

efficiency. 

Advancements in Plug & Perf Hardware 

For years, both cast iron and retrievable–type bridge plugs have been popular with oil and gas operators 

for achieving zonal isolation in multi–zone wells in order to perforate, treat, or isolate the zones 

independently for remedial work without damaging the formation. However, while either of these tools 

offers an acceptable solution, both present new challenges. 

Operators using cast iron bridge plugs must remove them by drilling them out of the wellbore. Following 

drill out, the cast iron cuttings require heavy fluids to remove them from the wellbore due to their 

weight. 


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On the other hand, retrievable–type bridge plugs require extra time to set and retrieve from the 

wellbore and they can require twice as many trips in the hole. 

To overcome these problems, composite bridge plugs, flow-thru composite frac plugs and squeeze 

packers were developed. They are constructed of high–strength, lightweight, composite materials and 

standard drillable elements that make them easy to drill out while maintaining their reliability. These 

"composite" tools do not have the long life spans of other types of plugs such as cast iron but their 

longevity is not a concern because their useful life is of such short duration. Their more important 

benefit is the ease and speed at which they can be removed from the wellbore after the job is finished. 

When compared to cast iron plugs, the average composite plug drill out time is remarkably less. Cast 

iron bridge plugs require as much as four hours or more to drill out compared to an average of 35 

minutes for a composite plug. Additionally, the light weight composite material that the bridge and frac 

plugs are composed of enables their cuttings to be easily circulated back to the surface in lightweight, 

non–damaging drilling fluids. 

In the late 1990’s, composite perf & plug tools were developed and they have continued to evolve to 

improve efficiencies in the completions process. The new plugs are made of composite materials and 

are employed similarly to conventional permanent bridge plugs. They are available in standard and 

high–pressure/high-temperature (HP/HT) models and setting equipment is identical for both versions. 

A Flow-Thru Composite Frac Plug (FTCFP) is a specific tool that works as a bridge plug when the pressure 

above it (such as during a fracture treatment) is higher. Then, when the pressure above is lower than 

the pressure below (such as when flowing the well back), the FTCFP allows fluid-flow from below 

through the plug. Using FTCFPs also allows all zones to produce during the completion of the well. Two 

benefits to this are that 1), no zones are shut-in for long periods of time, and 2), when the bottomhole 

flowing pressure is reduced during flow back, all previously treated zones help to clean up each new 

treatment. After a well is completed, the FTCFPs can easily be drilled out or left in the well. There are a 

variety of FTCFPs on the market today. All of them provide essentially the same function; isolate lower 

stages from the fracture treatment, and then, allow all the zones to produce during completions. Some 

of them have a one-way float, or ball built inside the tool; others have a ball cage on the top, and finally, 

there are the ones that have a free floating heavy ball. 

FTCFP are capable of addressing the current needs to reduce operational costs and improve 

productivity. These plugs can be used as an alternative to traditional isolation methods, or induced 

stress diversion. The benefits gained from FTCFP usage are derived from the following: being that well 

drill-out isn’t required costs are reduced, positive isolation is allowed, and all zones can be produced 

during completion. 


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Some of the benefits that are being seen today from technology advanced composite tools: 

• Cut days off fracturing procedures 

• Eliminate workover rig costs 

• Eliminate formation-damaging kill fluids 

• Save hours of costly rig drilling out time compared to other completion tools 

• Bridge plugs hold pressure from above and below 

• Maximum pressure and temperature 10,000 psi and 300 degrees F 

Sliding Sleeve Ball Activated Process 

To improve efficiency by reducing the time between fracturing treatments a completion using ball 

activated sliding sleeves was developed. Sliding sleeves are activated by pumping down balls or plugs 

which land on internal baffles plates to cause ports or windows in the casing to shift open. This 

technology has been used in the industry for many years as a method for performing multi-stage 

cementing in a clean wellbore. For fracturing operations a number of these sleeves can be run in series 

using baffle plates that have progressively larger internal diameter from the tow toward the heel of the 

horizontal lateral. Individual sleeves can then be opened by pumping the corresponding ball with a 

diameter slightly larger than the diameter of the baffle plate. When the ball seats on the baffle plate 

blocking flow to a previously stimulated interval, continued pressure increases and the sleeve shears a 

pre-determined number of locking pins and shifts the internal sleeve to expose external ports in the 

open position. In the open position with the ball on seat the fluid being pumped is diverted to a new 

interval. 

Figure 3-93, Ball Activated Sliding Sleeve Completion 

Performing a multi-interval completion in this way can eliminate the time between fracturing 

treatments making the process a continuous pumping operation. Diversion is controlled by the balls on 

seat in the baffle plates and on the casing annulus by external casing swellable packers or hydraulically 

activated external casing packers. The balls can be flowed back and recovered on surface but if a 

remediation such as wellbore cleanout is required the baffle plates are often milled out. 


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The overall process is extremely efficient provided there are no unplanned events. But there are a 

number of common events that can have a dramatic impact on efficiency and effectiveness of this 

process: 

• As the number of zones increases, the ball seat diameter in the lower zones decreases resulting 

in flow restriction and reduces the number of individual zones that can be stimulated. 

• Cemented completions present a problem for this type of completion due to the casing 

restrictions from the baffle plates. Conventional cement wiper plugs are not appropriate. Foam 

dart-type wiper plugs have been used but there is a risk of prematurely opening a sleeve with 

this type of operation. 

• Pumping the balls down to activate the tools often involves over-flushing the previously 

stimulated interval. 

• The costs of the sleeve tools and external casing packers could add to the overall completion 

cost. 

Advancements in Sliding Sleeve Technology 

A multi-fracture per isolation zone system provides operators new options for completing horizontal 

multi-zone wellbores to enable highly accurate placement of fractures, with minimal or no intervention. 

The system incorporates three proven, reliable systems – the sliding sleeve, initiator sleeve and the 

swellable packer isolation system – to allow operators to access multiple fracture points within an 

isolated interval. The completion assembly can be run into the wellbore using the liner hanger system 

or production casing to surface. The ball-activated system enables a totally interventionless completion. 

The system uses multiple fracture sleeves and a sliding sleeve within a single interval. This exposes the 

reservoir face to multiple fracture points, similar to the “plug and perf” process, without the loss of 

time, waste of water resources or extended exposure of personnel. Up to six fracture points can be 

used within an interval isolated by the swellable packer in a given zone. Up to 15 zones can be used for 

the completion. This results in up to 90 fracture sleeves that can be used in one horizontal completion. 

This advancement allows for continuous pumping of multi-zone treatments, and helps reduce 

completion cycle time and improve production. 

Pinpoint Stimulation Processes 

Pinpoint Stimulation fracturing methods represent a departure from the conventional approach 

previously mentioned. Multiple interval completions provide assurance that all intervals receive the 

designed proppant volumes – one interval at a time. To accomplish the efficiency coiled tubing is used 

to hydra-jet perforate intervals for individual fracturing treatments. 

Proppant plugs can be used not only for isolating previously stimulated intervals but also for maximizing 

near-wellbore conductivity for long-term production performance – critical in more ductile rock under 

high stress. These fracturing methods do not require removing the coiled tubing from the well between 

treatments and contingencies for early screen-out can be remediated immediately with minimal impact 

on overall completion costs. Treating intervals individually substantially reduces the amount of hydraulic 

horsepower required onsite which reduces the footprint of the completion operation, requires fewer 


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personnel onsite during the operation, and assures each interval receives the optimum fracturing 

treatment. 

Hydra-Jet Assisted Fracturing Method (HJAF) 

HydraJetting, the use of water under high pressure, is a well-known technique that many industries use 

to perform different tasks. These tasks range from cleaning and preparing surfaces, placing cements, 

drilling, cutting, slotting, perforating, machining, grouting, and mining to household uses, such as car 

washing and dental hygiene. One common function of the hydrojet or HydraJet (if other abrasive, such 

as sand, is used) is that its high-power energy is concentrated or focused on its target. In the oil industry, 

the most common applications for HydraJetting are slotting (cutting) or perforating. In these 

applications, sand performs the abrasive cutting function. Over time, jet-system quality has improved 

dramatically, resulting in greater resistance to abrasives and various chemicals and significantly 

increased tool life. Using this improved jetting tool, the HJAF technology has been effectively used in 

stimulation of horizontal well completions. 

Originally developed for open hole horizontal completions the HJAF method relies on stagnation 

pressure fracture initiation and dynamic diversion inherent in the use of hydra-jet energy while 

fracturing. The process has been used effectively in cased and cemented applications. 

In the HJAF process, the fracturing fluids (with sand) are injected through the tubing while clean fluids 

are pumped down the annulus. The annulus pressure is controlled as such that downhole bottomhole 

pressure (BHP) is slightly below the fracture-initiation pressure. As a sand pill hits the wall, it forms a 

cavity within seconds. The annular pressure is maintained constant as per leak off. Initially, the fluid 

entering the perforation cavity refluxes into the annulus because it has nowhere to go. As the cavity is 

formed, pressure on the bottom of the cavity increases. Fluid inside the cavity continues to increase and 

fracture initiation takes place with fluid entering into the formation. There is no need for mechanical 

isolation with this process and the time between treatments is based on the time to move tubing from 

one target interval to the next. 

Figure 3-94, - Hydra-Jet Assisted Fracturing Method 


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The bottom-hole assembly has undergone dramatic improvement to extend the life of the jetting device 

since the early days of its use. Jetting tools as late as 2009 were limited to less than 50,000 lbs of 

proppant per jet which meant the bottomhole assembly would need to be changed often for a multiple 

interval completion. The trip time for this operation resulted in excessive non-productive time for the 

fracturing equipment. Today’s technology has extended the life of these tools by a factor of 10 meaning 

the number if treatments that can be reliably placed before replacing the BHA has increased 10-fold as 

compared to more conventional jetting tools. Completions with more than 20 individual fracture 

treatments have been placed in one run into the well with over 1,000,000 lbs of proppant placed. 

Hydra-Jet Perforating and Annular Coiled Tubing Fracturing Method (HP-ACT) 

Some reservoirs, particularly when the rock is ductile or moderately brittle, require higher proppant 

concentration with no overflushing of the perforations to offset effects of proppant embedment. One 

way to assure conductivity near-wellbore is to intentionally screen-out the perforations at the end of a 

fracture treatment. This proppant plug that results from an intentional screen-out can be useful in 

diverting fluid for further treatments up hole while protecting previously treated intervals. 

Coiled tubing can be useful for managing the excess proppant in the wellbore as well as provide a means 

of hydra-jet perforating the casing and initiating the fracture. To prolong the life of the jetting tool it is 

used for hydra-jetting perforating, only. The main fracture treatment is pumped down the annulus of 

the casing and coiled tubing. The low injection rate required for the hydra-jet perforating operations 

allows for using more conventional size coiled tubing (1-3/4” and 2”). When the bottomhole assembly 

includes the latest jetting tool technology the number of treatments that can be performed in a single 

trip into the wellbore is increased dramatically – typically > 40 intervals per completion. 

Figure 3-95, HP-ACT Method using Coiled Tubing 

After all intervals have been treated, the same bottomhole assembly can be used to wash out the 

proppant plugs in a final wellbore clean-out operation with CT without tripping out of the well. Some 

reservoirs present problems when attempting to induce a screen-out at the end of each treatment. In 

the past it has been necessary to circulate down a proppant slurry to achieve sufficient bridging of the 

perforations and create a proppant pack inside the casing. Various techniques have been used to 


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improve the reliability of establishing the proppant pack of each treatment but this operation remains a 

process step frequently associated with non-productive time. 

Advancements in Pinpoint Stimulation Technology 

There are currently pinpoint stimulation completion services that enable placement of virtually 

unlimited number of fracturing stages in a horizontal section with the flexibility of on-demand, 

downhole changes in proppant concentration. These services uses high-rate pumping of non-abrasive 

fluid down the annulus mixed downhole with a proppant concentrated slurry being pumped down the 

tubing. As a result the rate down the annulus will be much higher, and can be manipulated to customize 

the placement and concentration of proppant being pumped down into the fracture. Real-time, 

downhole changes to proppant concentration help achieve optimum stimulated reservoir volume and 

connectivity to a larger fracture network. 


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3.5.3 Completion Method Comparison 

Several multiple-interval fracturing methods have been presented and each has a measure of benefits 

and drawbacks making it difficult to ascertain the appropriate method for a given completion scenario. 

Certainly the type of rock, whether brittle or ductile, and the zone thickness have a bearing on the 

selection criteria. Another technique to consider when choosing the appropriate completion method is 

to compare estimated total efficiency of the various fracturing methods for a given volume of fluid and 

proppant to be placed into a predetermined number of fractures for a given completion. 

To calculate the efficiency of each process a simple formula can be used with a focus on effective 

utilization of equipment during the fracturing process and the higher the number the better the 

efficiency. The total volume of proppant placed in the completion is divided by the total require 

hydraulic horsepower and then divided by the total time to place all treatments: 

Process efficiency is related to - lbs Proppant/HHP/hr 

Contingency cost can be evaluated by assuming a screen out occurs in one interval and applying the 

appropriate remediation method. The time required to re-establish the normal fracturing method 

process is the measure of the contingency cost. Obviously, the more pumping and associated equipment 

on location during the remediation the higher the impact on cost but this is not considered here. 

Finally, the optimum ‘clean’ time (meaning no unplanned events occur) can give a relative idea as to the 

overall time impact on the total completion. This time would include time spent after the fracturing 

process such as wellbore clean-outs or drill-outs of plugs. 

When the design for multiple intervals treated as a single stage is compared to processes that treat 

intervals individually, the multiple interval stage volumes and rates are divided by the number of 

perforated intervals to determine the rates and volumes of individual treated intervals. An example of 

the processes discussed in a generic completion job, assuming continuous fracturing is shown in Figure 

3-17. The corresponding results are shown in Figure 3-18. 


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Table 3-17, Job Parameter Comparison on Methods 

Perf & Plug Sliding Sleeve HJAF HP-ACT 

Total Intervals 30 30 30 30 

Perf Time/Stage 4 hrs 0.1 hrs 0.5 hrs 0.5 hrs 

Total Perf/Move Time 40 hrs 3 hrs 15 15 

# Intervals/Stage 3 1 1 1 

Treatment Rate 100-60 bpm 100-60 bpm 45-20 bpm 45-20 bpm 

Total Fluid Volume 1,500,000 gals 1,500,000 gals 1,500,000 gals 1,500,000 gals 

Total Proppant Volume 1,500,000 lbs 1,500,000 lbs 1,500,000 lbs 1,500,000 lbs 

Total Pumping Time 10.37 hrs 10.37 hrs 31.12 hrs 31.12 hrs 

Diversion Time/Stage 0 hrs 0 hrs 0 hrs 0.5 hrs 

Total Diversion Time 0 hrs 0 hrs 0 hrs 14.5 hrs 

Hydraulic Horsepower 30,000 HHP 30,000 HHP 15,000 HHP 14,000 HHP 

Total Frac Method Time 50.37 hrs 13.37 hrs 46.12 hrs 60.62 hrs 

Screenout Contingency Time 20 hrs 24 hrs 0.5 hrs 0.5 hrs 

Final Wellbore Cleanout Time 72 hrs 0 hrs 0 hrs 8 hrs 

Table 3-18, Comparison Results 

Fracture 

Method 

Perforating 

Diversion 

Efficiency (lbs 

proppant/HHP/hr) 

Contingency 

Cost, Hours 

Total 

Completion 

Time, Hours) 

Perf & Plug Select-Fire Composite Plug 0.99 20 122.37 

Sliding Sleeve Sliding Sleeve Ball & Seat 3.74 24 13.37 

HJAF Hydra-Jetting Dynamic 2.17 0.5 46.12 

JP-ACT Hydra-Jetting Packer or Sand Plug 1.77 0.5 68.62 

3.5.4 Completions Summary and Recommendations 

Many of the techniques discussed in this paper have proven successful in North America. To restate, the 

most common completion techniques seen in shale gas completion in the United States today are: 

• Plug and perf technique using drillable bridge plugs for isolation; 

• Ball drop or remote actuated sliding sleeve completions using open-hole packers in uncemented 

applications or cemented into place; and 

• Coiled-tubing assisted fracturing using HydraJet perforating and sand plugs for zone isolation. 

The completion recommendation for EBN is to adopt the third technique – coiled-tubing assisted 

fracturing and more specifically HydraJetting via coiled-tubing. This method facilitates stimulating 

multiple shale intervals with less than half the hydraulic horsepower requirements and a significantly 


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reduced footprint compared with other currently popular completion methods. This technology has 

significant potential because coiled tubing and HWO units are available in Europe. 


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4 Surface & Environmental Impacts 

4.1 Project Description 

The Scope of Work (SOW) for the Surface and Environmental Impacts team was to prepare a notional / 

feasibility level study to identify the potential environmental issues associated with the surface impacts 

associated with the development of shale gas resources within the Netherlands. 

4.1.1 Assumptions 

Our recommendations are based upon the data reviews, modeling and designs of the Subsurface Team, 

and input from EBN. Based upon information agreed to in our Peer Review meeting on September 24, 

2011, the following assumptions were used as the basis of our work. 

Resource play is a “dry gas.” 

Low potential for the presence of hydrogen sulfide (H 2 S). 

In order to maximize the potential production volumes of the play, the development will require 

horizontal drilling with hydraulic fracing. Since different lateral lengths and number/stages of 

fracs were modeled, it is important to clarify that our work is based upon the following 

information: 

Drilling depth of 3,100 meters 

o Lateral lengths of 1,500 meters on a 400-meter spacing 

o Designed for 22 frac stages 

o Each stage will require 3,000 barrels of water 

o Flowback is projected at 15 percent (%) of injected volume 

o Produced water is projected at 600 barrels per day (initial volumes could be as high as 

1,000 barrels per day) 

• Well pad footprint is estimated at 150 meters by 100 meters. 

• For each well pad, it is estimated that between one and 10 wells can be drilled to minimize the 

number of well pads required. 

• Within the identified “GO” sites, the intent would be to establish centralized water 

impoundments with piping systems to move the water between the well pads. 

• Al surface facilities must be designed in relation to potential seismic activity. 

4.1.2 Unknowns 

There are still many “unknowns” at this juncture of the study, which will be reduced as decisions are 

made regarding: 

• Location of first area to be explored 

• Capital budget to be invested 

• Schedule of resources allocated. 


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4.1.3 Hypothetical “Base Case” 

In order to complete our portion of the notional / feasibility study, we had to determine a means by 

which we could provide an overview of the Surface Issues that will need to be addressed as the project 

progresses. 

We selected a hypothetical location as a “Base Case” location and used this “Base Case” as a point of 

reference for our discussions. We used the following process to select the “Base Case”: 

• Discussions between EBN and Halliburton determined the basis for lateral layouts to maximize 

reservoir exposure in the areas designated between the faults in Zone 8C (this was an area 

highlighting the “best – sweet spot” reservoir. The boundaries of this initial iteration were 

arbitrary. 

• We reviewed the areas within Zone 8C to determine “favorable” locations (the NO-GO, MIGHT- 

GO, and GO process is described in more detail in Section 6.3 – Well Pad Construction). 

• Halliburton took the available “favorable” locations and performed modeling for possible well 

pad locations based upon a realistic approach to well design rather than maximum reservoir 

contact. 

• A listing of the 83 possible pad locations were identified and plotted on a map. 

• With local knowledge of the existing gas grid within the Netherlands a location should be chosen 

to minimize the infrastructure that would be required to get the shale gas to market. 

• In addition, it should be confirmed that local water boards would have sufficient “grey water” 

through-put, if that was the source water option ultimately selected. 

• Another consideration was the proximity to several surface water bodies nearby if the need for 

surface water as a source water becomes part of the equation. 

• While not knowing the number of wells that will be drilled and the timeline in which the wells 

would be drilled, we reviewed the production data provided by Halliburton and made a decision 

that for the purposes of our “Base Case,” that it was reasonable to assume that enough wells 

would be drilled and brought into production to foresee the need for a gas processing facility 

capable of handling 500,000 mcf of gas per day. 

• With industry knowledge that the gas processing facilities for “dry gas” are packaged units that 

are scalable up or down according to actual production volumes, we determined the need for a 

parcel of land of approximately 5 hectares for a centralized processing facility location. 

• It was presumed that the gas processing facility and a centralized impoundment for water 

storage could be co-located on the same parcel of land to minimize the footprint of gas 

development efforts. 

• In addition to the gas processing facility and centralized impoundment, it is assumed that the 5 

hectare parcel would provide sufficient space for mobile skid-mounted water treatment 

equipment to be stationed on the site to facilitate the treatment and blending of fresh water so 

as to enable the recycling and re-use of the flowback and produced water and minimize the 

volumes of fresh water needed to support the gas development. 

• Temporary water pipelines could be constructed to provide the fresh water to the well pads 

from the centralized impoundment and transfer the flowback and produced waters back to the 


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location for treatment, blending, and re-use of the water. 

We selected a parcel of land within Zone 8C that is in close proximity (5 kilometers) to a number of 

possible well pad locations (13 well pad sites) as our “Base Case” location from which to work. 

The Figure 4-1 below shows a location that we have selected within Zone 8C that will be referred to as 

our “Base Case” site. This is a hypothetical location and serves for discussion purposes only. 


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Figure 4-1. “Base Case” hypothetical location. 


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This location was selected based upon the following criteria: 

• Agriculture area within the established “GO” areas within Zone 8C 

• Availability of land (5 hectares) 

• Proximity (within 5 kilometers) of identified possible well pad sites (474, 208, 207, 203, 470, 517, 

509, 482, 480 92, 90, 66, and 619) 

• Proximity (within 5 kilometers) of the assumed location of the gas pipeline grid within the 

country 

• Proximity (within 5 kilometers) of alternative sources of water 

o Surface water / streams / rivers 

o “Grey water” from a local water board 

• Proximity to roadways for movement of equipment 

• Availability of utilities as source power for surface facilities 

If eight to 10 wells were drilled at each identified well pad site in the area referenced above (13 well pad 

sites), there is the potential of 104 to 130 wells being drilled in the area of our hypothetical site referred 

to as “Base Case” site. 


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4.2 Regulatory Framework 

4.2.1 Introduction 

We have reviewed the regulatory framework within the Netherlands as it applies to the development of 

shale gas resources, and provides the following summary. 

Various approvals are required for the extraction of shale gas, including land use, building and 

establishing surface and underground facilities, and the performance of actions that may influence the 

quantity and quality of (ground) water in protected nature (conservation) areas. This section discusses 

the most important laws and regulations. 

In principle, the various approvals that are needed require a range of legal proceedings. An exception 

however is the situation for which a special law is provided for the relevant actions. Here the National 

Coordination Regulation (NCR - rijkscoordinatieregeling) should be followed. Should such a case occur, 

most of the necessary approvals are prepared by the same procedure. 

In view of the above, the following information addresses the circumstances where the NCR might apply 

to this initiative. 


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4.2.2 National Coordination Regulation 

In 2010, the NCR for state, provinces, and municipalities came into force under the (new) Spatial 

Planning Act (SPA) (ref. par. 3.5.2., in particular 3.6.3, SPA). Further detail is available in paragraph 9a of 

the Mining Act (MA). 

The regulation aims to make the decision making process for (changes to) spatial plans and associated 

permitting procedures, faster and more efficient. The targeted efficiency improvement also proposes a 

preference for one governmental organization to become the responsible authority in the decision 

making process. 

Exploration and production (E&P) infrastructure projects have become subject to the regulation, as they 

concern large energy projects of national interest, that need to be incorporated into spatial plans. 

Article 141a of the MA declares this procedure applicable to mining activities (i.e. mining works): a) used 

in the exploration or production phase within or under certain nature conservation areas, b) for the 

storage of substances, and c) for pipelines (primarily or largely) related to the transport of natural 

resources resulting from the exploration or production thereof. 

This NCR is meant to shorten and streamline the time span of the large diversity of permit procedures 

involved in large-scale energy and infrastructure projects. The urban planning decision will take place on 

a central level, as does the coordination of the permits. By coordinating the preparation and handling of 

the permit procedures simultaneously, a better cooperation between authorities is realized and all 

relevant information can be considered in the decision making process. This coordination is linked to the 

Ministry Zoning Plan (MZP). 

Summarising, the NCR contains: 

• Notification of the project should be made to the Minister of Economic Affairs, Agriculture, 

and Innovation; 

• The Ministers of Economic Affairs, Agriculture, and Innovation and Infrastructure and 

Environment should determine a National Integration Plan (NIP) which is procedure for 

zoning at national level for spatial anchoring of the initiative 

• The procedures and required approvals for this integration plan are specific and require the 

Ministry of Economic Affairs, Agriculture and Innovation to render a decision on the 

application within +/- 6 months.; 

• Once an appeal at the Division of the Council of State (Department) has been filed, the 

Department is required to rule within six months after the appeal period (Article 1.6 Crisis 

and Recovery Law). 


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A provisional procedure is presented in the Figure 4-2 below. 

Figure 4-2. Provisional Procedure 

The overall timing of the procedure shown in the above figure is indicative. Some terms strongly depend 

on urgency, type, scale, and impact of activities to be undertaken. The duration, including 

administrative court procedure, is estimated at three years; however, potentially time can be saved in 

proper (pre-phase) preparations. As this procedure has only been established/ implemented in the 

Netherlands over the past two years, there is no practical experience available yet. However, a number 

of 10 to 15 projects are currently ongoing. 

Article 141c of the MA provides that more detailed rules can be set on the approvals that fall under the 

NCR anyway. These more detailed rules are set out in Article 4 of the Implementation Decree NCR 

energy-infrastructure projects. From this Article, it can be derived that the production license as 

mentioned in the MA does not fall under the NCR, but the production plan does. We elaborate on this in 

the next chapter. 

4.2.3 Mining Legislation 

The Mining Legislation (ML) contains rules regarding the exploration and extraction of minerals and 

activities related to mining activities. 

The ML, which was established in 2003, replaces a range of other legislations regarding mining activities. 

The Minister of Economic Affairs, Agriculture, and Innovation is the authority of the ML. Within this 

legislation, the storage and extraction of minerals from a depth of greater than (>) 100 meters is 

specifically included. 


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The ML mostly involves the requirements and conditions required to prevent dangerous incidents. 

Preventive measures can involve technical, organizational, procedural, or supervisory aspects. The ML 

regulates the use of underground areas, particularly permitting and decisions made by the Ministry of 

Economic Affairs, Agriculture, and Innovation. 

The ML implements the requirements that are set by relevant European Union (EU) guidelines by means 

of an exploration permit, an *extraction permit (which includes approval of the ‘so-called’ Production 

Plan), independent inspection by the State Supervision of Mines, (Dutch: Staatstoezicht op de Mijnen), 

and several general regulations regarding the design, operation, and monitoring of mining works where 

products are stored. 

Once exploration drills have shown that an economical extractable amount is achievable in the area, a 

production permit is requested. A production permit (concession) must be seen as an area reservation 

(consider ‘an area reserved for mining activities’) for mining activities. If the production permit is 

requested by someone other than the holder of the exploration permit, or is requested after the 

expiration date of the exploration permit, the Minister should give other parties the opportunity to 

apply for a production permit. In the permit application, the applicant must demonstrate that it is 

economically viable to extract the shale gas. Furthermore, the financial position and its possibilities, 

method of execution and social responsibility, must be described. 

If the permit is granted, a production plan must be submitted to the authority for approval. The 

production plan must address potential environmental impacts, any possible effects of ground 

movement (in terms of geotechnical/seismic activity), and safety concerns. 

Upon completion of the shale gas extraction, the well must be plugged and abandoned (P&A) in 

accordance with the applicable regulations. Included in this P&A process of the dismantling and removal 

of any surface facilities and the extraction sites should be restored to its original condition. In addition, 

any pipelines or cables should be removed, unless the landowner elects to keep the pipeline/cable. 

4.2.3.1 Procedure and authority production permit 

The production permit is granted by the Minister of Economic Affairs, Agriculture, and Innovation. As 

concluded in previous section, in principle, the NCR does not affect the production permit. The ML 

procedure should be reviewed to complete the permit. 

Under Article 17 section 1 of the ML, the Minister of Economic Affairs, Agriculture, and Innovation 

should, in principle, render a decision within six months on the application. This review can be extended 

one time for a period of six months. Additionally, a longer period is applicable if other parties should be 

invited to apply for a production permit (this situation is described above). The stakeholder should have 


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first rights to object to the decision for the application of a production permit. Objection against the 

decision is possible through the State Division of State Council (Article 142 ML). 

4.2.3.2 Procedure and authority production plan 

Unlike the production permit, the production plan falls under the NCR as applicable to the initiative. The 

procedure is referred to in the previous section that relates to the NCR. 

Even if the NCR would not apply, the uniform, public preparation procedure of Section 3.4 of the 

General Administrative Law (GAL) is applicable to the production plan. This means that a first draft of 

the production plan should be made available for public review and objections may be filed. The 

Minister of Economic Affairs, Agriculture, and Innovation has six months to render a decision on 

whether or not to approve the production plan as submitted. Appeals of their decision may be filed 

with the Division of the Council of State. 

4.2.4 Decree General Environmental Rules - Mining Activities 

The Decree General Environmental Rules – Mining Activities (Barmm) is applicable to temporary mobile 

installations for the construction, testing, maintenance, repair, or decommissioning of a borehole. In 

this scenario which involves the more permanent extraction of minerals, for which the permit 

application process applies, this decree is therefore not applicable. 

4.2.5 Spatial Planning Act 

The Spatial Planning Act (SPA) regulates the establishment and modification of spatial planning in the 

Netherlands. The law requires local governments to draw up more indicative plans (structural visions), 

but also applies to civic integration and binding zoning. Furthermore, the law provides the opportunity 

to lay out general spatial rules, which work through in lower planning. 

The buildings, pipelines, and other installations associated with gas extraction should be reviewed in 

relation to existing zoning requirements. It may be presumed that the zoning does not allow for a major 

gas extraction development project, so a zoning variance procedure is necessary. The zoning criterion is 

“good spatial planning.” As part of this variance request, the effects of the plan will be examined to 

ensure they are consistent with the planning policy, and that the environmental and nature standards 

are not violated. 

4.2.5.1 Procedure and authority 

In principle, a zoning plan is set by the town council. In cases where the NCR is applicable, the Ministers 

of Infrastructure and Environment, Economic Affairs, Agriculture, and Innovation, shall determine a 

governmental integration plan. Other decisions considered to be necessary, will be prepared in parallel 

to the integration plan’s development procedure. 


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Regardless of the applicability of the NCR, the plan is prepared using the uniform public preparation 

procedure of section 3.4 of the GAL. This means that the draft of the integration or zoning plan should 

be available for public review for six weeks. During these six weeks, objections to the draft plan can be 

filed. Appeals of the final decision are handled by the Department of Administrative Law, at the Council 

of State. 

4.2.6 General Provisions Environmental Law 

On 1 October 2010, the General Provisions Environmental Law (Wabo - Dutch: Wet algemene 

bepalingen omgevingsrecht, ) were implemented The Wabo contains various rules and frameworks for 

activities that may affect the physical environment and was established to provide a simplified and 

faster permit application process and improved public services by the government for building, space, 

and the environment. 

The ‘all-in-one’ permit for physical aspects (known as the All-in-One permit) is one integrated permit for 

building, housing, monuments, space, nature, and environment. The General Provisions Environmental 

Law imposes requirements on localised projects that may affect the physical environment. For shale gas 

extraction, the environment and building requirements are especially relevant. Any possible effects on 

protected nature conservation areas play a role. These are discussed separately in the relevant sections 

in this report. 

Although the purpose of the Wabo is to grant a permit for the entire project, it can be assumed - given 

the distance between the well pads - that each location would require an ‘All-In-One’ permit. 

4.2.6.1 Environment 

For the establishment of a facility that is essentially a mining activity, an ‘All-In-One’ permit must be 

obtained. The permit application must be reviewed from the perspective of protecting the 

environment. The best available techniques and the threshold values for air quality, external safety, soil 

protection, vibrations, and sound should be verified in this framework. Also, subordinate legislation, 

such as the municipal and provincial environmental policies would need to be considered. 

4.2.6.2 Building 

The building of surface structures that are necessary for gas extraction, without an ‘All-In-One’ permit is 

prohibited. For the component building, the ‘All-In-One’ permit should be denied if the structure does 

not comply with requirements for housing, the building code and prosperity, or if the building is in 

violation of zoning. 


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The ‘All-In-One’ permit must be submitted to the Minister of Economic Affairs, Agriculture, and 

Innovation. Both with and without the application of the NCR, the permit is prepared with the uniform 

public preparation procedure of Section 3.4 of the General Administrative Law. This means a draft of 

the environmental permit should be made available for public review and the Minister shall grant or 

reject the application within six months (+ one extension of six weeks). 

Where the NCR is applicable, an appeal of the final decision should be made through the Department of 

Administrative Law at the Council of State. Where the NCR is not applicable, first appeal has to be 

brought before court, administrative law, and after that, it is possible to appeal to the Department. 

4.2.7 Water Act 

The Water Act (WA) is formed by the integration of eight historic water laws. The main purpose of the 

WA is the instrumentation of integrated water management. The WA covers quality and quantity of 

surface water, groundwater and the protection of water management works, such as dams. 


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Figure 4-3. Surface water in the Netherlands 


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The following activities associated with shale gas extraction are subject to the WA regulations: 

· The extraction of groundwater and/or surface water; 

· The infiltration of water into the soil (fracking activities); 

· The discharge of substances into surface water; 

· Operations in, on, or near water management works; 

· Works in violation of an applicable local “Keur” regulation. 

Regarding the extraction of groundwater, the law is restricted to a depth of 500 meters below ground 

level (Article 6.12, part d). If one or more of these actions take place, one water permit per location is 

applicable. As part of permitting review process, water quality, quantity and ecological aspects will be 

assessed. 


The water permit is granted by the agency with highest authority, which depending on the type of 

activity and the status of the surface water would be either the Department of Waterways or Public 

Works for groundwater extraction and/or infiltration (Provincial Executive of Noord Brabant). 

Where the NCR is applicable, the water permit – like the necessary integration plan – is prepared 

uniformly and publicly. Appeal will be made through the Department of the Council of State. Where the 

NCR is not applicable, the preparation procedure depends on the type of activity. Where the activity is a 

direct discharge on surface water, extraction of groundwater, or infiltration of water, a decision period 

of six months for the uniform public preparation applies for the water permit. There is an established 

process whereby stakeholders can appeal the final decision of the permitting authority. In all other 

cases, a review period of eight weeks applies and the first objection has to be submitted before an 

appeal can be filed. Where the NCR is not applicable, an appeal is filed with the Department of 

Administrative Law at the Council of State. 

4.2.8 Nature Protection Act - 1998 

The Nature Protection Act (NPA) of 1998 contains rules pertaining to protected nature conservation 

areas. This includes both protected natural monuments and Natura-2000 areas. 


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It is possible that animal species are susceptible to the effects of sound and light. Nitrogen emissions can 

lead to an increase in deposits of nitrogen in protected habitats. Where these effects can worsen or 

have a significantly disruptive effect on species, a permit under the NPA 1998 is required. Permitting is 

reviewed against the conservation objectives set for the area. 

If the project on its own, or in conjunction with other projects or plans, could have significant 

consequences for the relevant Natura-2000 areas, an appropriate assessment has to be added to the 

application (Article 19f, NPA 1998). It is recommended that any possible effects on nature are explored 

using a pre-verification assessment. Only when completed, can we draw conclusions about whether an 

appropriate assessment is necessary. These conclusions are important for the plan’s required 

Environmental Impact Assessment (EIA). See the section under Environmental Management Act 

pertaining to an environmental impact assessment. 


If the activity for which an environmental permit is required also requires a permit under the NPA 1998, 

the nature section becomes part of the ‘All-in-One’ permit for physical aspects (All-in-one permit). The 

preparation of the decision is referred to concisely in the section under Wabo, and where applicable, to 

the section about the NCR. 

Combination of the NPA and the ‘All-in-one’ permit can be prevented by applying for the NCR in an 

earlier stage. In that case, the Minister of Economic Affairs, Agriculture and Innovation is the authority 

to grant the NPA permit. The permit review period is 13 weeks, with one possible 13 week extension. 

Appeal of the decision would be filed with the Department Administrative Law at the Council of State. 

4.2.9 Flora and Fauna Act 

The Flora and Fauna Act contain rules for the protection of wild plants and animals. The law covers all 

operations that are carried out, and which may affect flora and fauna. 

If the activities associated with shale gas development were to impact fauna or flora then the provisions 

of the Flora and Fauna Act would apply. This also depends on the season during which the project will 

take place. Disruptive activities that occur during the extraction of shale gas may include: drilling, 

pipeline construction, construction of well pads and other installations. Given the nature of the work, a 

waiver under the Flora and Fauna act would be required. 


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Figure 4-4. Wetlands area 


If an activity, for which an ‘All-in-one’ permit is required, also requires a waiver based on the Flora and 

Fauna Act, the nature section becomes part of the ‘All-in-one’ permit for physical aspects (All-in-one 

permit). The preparation of the decision is summarized in the section under Wabo, and where 

applicable, to the section about the NCR. 

This combination can be avoided if a waiver is applied for at an earlier stage. In this case, the Minister of 

Economic Affairs, Agriculture and Innovation remains the authority, however the decision period is 16 

weeks. Stakeholders protesting the decision on the Flora and Fauna waiver should first file an appeal 

with the Department Administrative Law at the Council of State. 

4.2.10 Excavations Act 

The Excavations Act contains rules relating to all excavations; excavation without a permit is prohibited. 

An excavation permit is necessary for the construction of a water basin and/or for the drilling of holes, 

dependent on exact measurements. 


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Figure 4-5. Excavation equipment 

4.2.10.1 Procedure and Authority 

The authority for granting the permit rests with the Provincial Executive of the Noord Brabant province. 

Regardless of the way in which the NCR is applied, a decision based on an application for an excavation 

permit, is prepared using the uniform public preparation procedure of Section 3.4 of the General 

Administrative Law. The decision period is six months. Within this period a draft of the permit should be 

made available for anyone to review. During this six week period, objections to the draft can be lodged. 

Appeals against the final decision can be lodged directly with the Council of State at the Department of 

Administrative Law (Article 17 of the Excavations Law). 

4.2.11 Soil Protection Act 

The Soil Protection Act contains rules relating to soil protection, in particular those rules that prevent 

soil contamination and remediation of new contamination. 

Under the Soil Protection Act, a duty to prevent soil contamination rests with everyone. This means that 

no new soil contaminations may occur or existing pollutions spread further. Both elements are 

important for and relate to the extraction of shale gas. Should any contamination occur, a reporting 

duty exists and the damage shall be remediated as soon as possible. 


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As part of the environmental permit, an environmental analysis should be carried out according to 

Dutch Soil Protection Guidelines (NRB). This should demonstrate that the risk of soil contamination, as 

result of the activities, is reduced to a negligible risk. 

4.2.12 Environmental Management Act / Decree Environmental Impact 

Assessment 

The main purpose of the Environmental Management Act (EMA) is the protection of the physical 

environment. Before 1 October 2010, this Act formed the basis for the environmental permit; however, 

this was before the introduction of the Wabo which facilitates the ‘All-in-one’ permit for physical 

aspects. The EMA is still an important Act for anchoring environmental quality demands, including air 

quality and external safety. Furthermore, the EMA has a provision for ‘policies on environmental 

damage or the imminent threat thereof’. Because these articles are present in the EMA, the legislature 

has implemented the Environmental Liability Directive (2004/35/EG) into Dutch legislation. 

The EMA sets the basis for conducting an EIA for activities that may have a potential environmental 

impact, which means it is particularly important for this framework. In the Netherlands a distinction is 

made between a plan and project EIA. 

4.2.12.1 Plan EIA 

If the realization of gas production is foreseen, a plan EIA should be prepared if an assessment is 

required within the framework of a zoning or integration plan. 

As previously noted, the need for this should be confirmed by an environmental pre-verification process. 

In addition, a plan EIA should be prepared in advance of preparation for a plan which sets the 

framework for the activity which is being subjected to an EIA evaluation. It can be expected that for the 

zoning or integration plan, a plan EIA should be prepared. This is due to the nature of the framework of 

activities under C 17.2 and D 17.2 / D 29.2, for which an EIA evaluation is required, and possibly due to 

the expected effects on nature. 

Among other things alternative locations for the project are part of the plan EIA. 

4.2.12.2 Project EIA 

For the present initiative, a project EIA is required if the activity occurs in Annex C of the Decree EIA. 

This is the case when more than 500.000 m3 of natural gas per day is extracted (category C 17.2). In a 

project EIA, the installation alternatives, rather than the location alternatives, are important. When the 

initiative is not mentioned in Annex C, it is necessary to consider whether it is mentioned in Annex D. If 

this is the case, an EIA assessment is required. The criteria indicate that where significant adverse 

environmental effects can occur, the preparation of an EIA is required. 


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The “plan EIA” requires compliance with an extensive procedure process (shown in the Table 4-1. 

Comparison of Limited and Extensive EIA Procedures) and is linked to the process for determining the 

zoning or integration plan and should be included when the draft plan is made available for public 

review. Determining which institution is the correct authority for the “plan EIA” is dependent upon 

whether or not the NCR is applicable. Where the NCR is applicable, the Ministers of Economic Affairs, 

Agriculture and Innovation, and Infrastructure and Environment, would be the appropriate authority. 

The “project EIA” procedure is linked to the preparation of the ‘All-in-one’ permit. If required it may also 

be linked to the excavation permit (if required), and to the water permit (if discharge into surface water 

occurs). Regardless of the applicability of the NCR, the Minister of Economic Affairs, Agriculture and 

Innovation is the authority for the project EIA. However, joint authority with the General Executive of 

Noord Brabant and the Department of Waterways or Public Works, is possible. If an assessment for the 

project EIA activity is required, the project EIA is also prepared using the extensive EIA procedure (see 

table below). 

Table 4-1. Comparison of Limited and Extensive EIA Procedures 

Limited procedure 

Extensive procedure 

Notification by initiator to authority 

Notification by initiator to authority 

(at project) 

No notification 

Public notification 

Possible consultation with consultants and involved Always consult with consultants and involved 

governmental agencies about scope and detail governmental agencies about scope and detail 

No obligation to submissions on the initiative. 

Obligation to submission opinions on the initiative 

On request: 

Advice EIA Committee about scope and detail 

On request: 

Advice EIA Committee about scope and detail 

Possibly advice authority about scope and detail (at If authority ≠ initiator 

request of initiator or on own initiative) 

Advice authority about scope and detail (at project) 

Prepare EIA 

Make EIA public 

Obligation to review objections to the EIA 

At request: assessment advice EIA Committee 

Decision including motivation 

Publically announce decision 

Evaluation 

Prepare EIA 

Make EIA public 

Obligation to review objections to the EIA 

Mandatory assessment advice EIA Committee 

Determination of plan / decision including 

motivation 

Publically announce plan / decision 

Evaluation 


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When both plan and project EIA are required, both EIAs may be combined. If this is the case, the 

extensive EIA procedure is followed for the combined EIA. 

4.2.13 Summary 

Extraction permit 

(Mining Act) 

Grievance 

procedure 

Appeal procedure (Council of 

State) 

All permits are 

irrevocable 

Spatial zoning procedure 

(via NCR) 

Extraction plan (Mining Act) 

Preparation / EIA 

} 

All in one permit for 

physical aspects 

Water Permit 

} 

Appeal procedure 

(Council of State) 

Excavation Permit 

2 year 34 weeks 32 weeks 

Total: 

170 weeks 

Figure 4-6. Procedures and Permits via NCR 


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Preparation / EIA 

Spatial zoning procedure 

Appeal procedure (Administrative 

court) 

Last permits are 

irrevocable 

Extraction permit 

(Mining Act) 

Grievance 

procedure 

Appeal procedure (Council of 

State) 

Extraction plan (Mining 

Act) 



} 

All in one permit for 

physical aspects 

Water Permit 


court) 


court) 

Further appeal 


Further appeal 


Excavation Permit 



Total: 

2 year 13 weeks 

26 weeks 

1 year 

40 weeks 

235 weeks 

Figure 4-7. Procedures and Permits without NCR 

4.2.14 Natural Resources - Ownership Principle and Land Access 

Article 3 of the MA stipulates that natural resources belong to the State, and that the ownership thereof 

transfers, once produced, to the license holder. Since hydrocarbons are defined in the MA as a subgroup 

of ‘natural resources’, this also includes (shale) oil and gas. 

The Mining License provides the license holder (geographical) exclusivity regarding mining activities in 

the licensed area (Art. 6). It is important to note that in 2009, an amendment to the MA was agreed to in 

Parliament, which provides the Minister the opportunity to reduce the size and/or duration of a license, 

if it appears that no actual (‘significant’) activities are being undertaken by the operator within a certain 

area. This amendment has been made to stimulate mining activities within a license. 


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4.2.14.1 Land access 

According to Article 4 of the MA, landowners within a license have to allow all mining activities that take 

place deeper than 100 meters below ground level. In case of refusal, a court order might be required. 

This can easily take longer than a year. 

There are different approaches to achieve an approval for land use with a landowner. 

The approach to follow depends on future investment at a site and the approach taken by the E&P 

Operator/developer. In general, the operator would prefer to become landowner of sites where wells or 

production station(s) will be situated, or if a long duration of activities is foreseen. This includes (certain 

rights with respect to) a certain buffer zone around the facilities. However, a rent or lease (sale/saleback) 

construction (agreement) may be better suited, in cases where exploratory drilling takes place, 

and where duration of activities are expected to be undertaken within a far shorter timeframe. 

It is more common to achieve a settlement of Business Rights for the routing of (underground) pipelines, 

in accordance with Dutch law (via an annual or ‘one-off’ payment). In all cases, there is an obligation to 

compensate the landowner for damage (if any) and the use of the property (ref. article 4, MA). 

Settlement of Business Right to use the property; 

After constructing a well pad and/or a pipeline, a Settlement of Business Rights should be prepared to 

ensure an operator has the right (to drill) on a landowner’s property. This settlement of Business Rights 

is a clear and transparent contract between the operator and landowner, which stipulates the juridical 

property of the pad, the well, and the pipeline, and practical appointments such as service activities, 

repair, access etc. Furthermore, this contract defines the rules for compensation in case of damage, 

disputes or any other irregularities. An environmental ’base-line’-survey (‘0’-study) is conducted, and 

then added as part of the agreement. 

Amicable expropriation of the property; 

During the design phase of the project (in particular towards the large scale production phase), a 

landowner feasibility study needs to be conducted. This study should provide an overview of 

landowners who are willing to cooperate on the roll-out of the infrastructure (access roads, well pads 

and pipeline routes). Such an approach should make it possible to acquire a property portfolio via 

amicable expropriation. After selecting the most suitable instrument per landowner, the execution 

stage follows. This will include all aspects of the expropriation, including negotiation, taxation, 

settlement of the contract and entry into the national land registry (‘Kadaster’). 

As a final remark on the subject of land access: In case the ‘National Coordination Procedure’ (NCP) is 

declared applicable, additional powers to enforce dispossession are assigned to the Minister related to 

the use and acquisition of private plots. 


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4.3 Comprehensive Water Management Planning 

Water management is an essential component of any shale gas development program. This section will 

address the various components of a water management plan. 

Figure 4-8. Fresh water impoundment used to store water for fracking 


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4.3.1 Potential Water Sources 

A review of potentially available water sources was carried out in the area surrounding the proposed 

well field development. The following is a summary of findings. 

This section covers the issues that relate to the quality and quantity of water that could be used for 

fracking operations in the area defined as Zone 8C in the province of Noord-Brabant. Different water 

sources were considered for the overall availability of water, subject to necessary approvals and laws. 

· Drinking water 

· Ground water (fresh and brackish) 

· Surface water 

· Effluent from waste water treatment plants (WWTP) 

4.3.1.1 Drinking Water 

• The drinking water supply grid in the Netherlands is very well developed. (> 99 % of every 

household has a drinking water connection). 

• According to Dutch standards, water quality is far higher than the World Health Organization 

(WHO) standard (Cl- < 100 mg/l, pH 7,8 – 8,3 and Ca< 80 mg/l). 

• In the Netherlands, the use any form of chlorine to disinfect drinking water, including surface 

water is prohibited. However, disinfection is not necessary because the drinking water (source 

groundwater in the province of Noord Brabant) is free of pathogens and viruses. In addition, 

with leakage of less than 3 – 4 %, the drinking water distribution grid is always under pressure. 

Drinking water companies in the Netherlands have an average ‘non-delivery’ record of less than 

15 minutes per year. 

• “All in price” per m 3 needs to be verified (pressure at least 1 bar, most of the time at least 2 bar). 

Discounts may be available for industrial usage. 

• In the province of North Brabant, the drinking water supply is provided by Brabant Water, which 

is wholly owned by the public. 

• The capacity of water available depends on the location, in relation to the rest of the capacity in 

the drinking water distribution network. Capacity is also dependent on whether or not a 

drinking water pump station(s) in the vicinity has residual capacity. 

• Actual water availability depends on the time of day and season. Drinking water will be limited 

or unavailable between 6:00am and 9:00am, and between 5:00pm and 9:00pm. At night, water 

buffers are filled to meet the water demands of the day. In general, water demand is higher 

during summer and lower in winter. Although maintenance activities are planned during these 

periods of low demand, the highest available water capacity will be during the winter months. 


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In Table 4-2. Technical maximum capacity of different drinking water pipes based on their size the 

network distributing drinking water in Zone 8C includes the possible residual capacity of some drinking 

water pumping stations (note residual is per year and needs some translation). This information is also 

incorporated in the GIS model. 

Although residual capacity is available according to the permit, the situation might be that the particular 

water treatment plant (WTP) was not constructed to its full permitting capacity. The technical 

maximum for each of the network pipes depends on the water flow rate. Table 4-2 presents the total 

capacity based on flow rates of 1 m/s (realistic) and 2 m/s (maximum). Note the data presented does 

not represent the actual capacities that can be withdrawn from the drinking water network. The actual 

through-put will depend upon water resistance within the pipes and the required remaining pressure in 

the network. Therefore all data for each pumping station will need to be verified with Brabant Water. 

Table 4-2. Technical maximum capacity of different drinking water pipes based on their size 

Flow rate: 1 m/s 

Flow rate: 2 m/s 

Pipe diameter (mm) Capacity (m 3 /h) Pipe diameter (mm) Capacity (m 3 /h) 

100 - 200 28 - 113 100 - 200 57 – 226 

201 – 300 113 – 254 201 – 300 226 – 509 

301 – 400 254 – 452 301 – 400 509 – 905 

401 - 500 452 – 707 401 - 500 905 – 1414 

> 501 > 707 > 501 > 1414 

The map below shows the existing water pipelines in the area of our “Base Case” site. It appears the 

water infrastructure near the location is in place. The additional water pipeline infrastructure required 

would be minimal. 


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Figure 4-9. Water supply distribution pipelines in the area of the Base Case site 

4.3.1.2 Groundwater (Fresh) 

The policy for the management of ground water storage in Noord-Brabant is defined in the Provincial 

Water Plan 2010-2015. The policy is to reserve clean deep groundwater for public water supply, and 

protect it against over-exploitation. Deploying targeted policies for different user groups of 

groundwater abstraction have been successful. The total amount of groundwater abstracted by drinking 

and industrial water suppliers has stabilized during the past 20 years. 

Elements of the province’s general policy are defined in paragraph 11.2 of the mentioned ‘Provincial 

Water Plan’. 

· Groundwater is used for human consumption (public water supply and industrial applications). 

Alternatives are needed for other low-value applications. 

· The goal is to preserve the quality of groundwater in order to guarantee the long term supply of 

public water. The starting point is to withdraw groundwater no deeper than 80 meters. 


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· No new permits for deep extractions. 

· No increase of the total groundwater abstraction. With reductions elsewhere, more industrial 

use is possible. 

4.3.1.3 Groundwater (Brackish) 

Currently the use of brackish groundwater, which is free of manmade pollutants, is being evaluated and 

some pilot projects are being carried out, including one by Brabant Water. Extracting brackish 

groundwater could improve the supply of fresh groundwater (lowering the brackish groundwater 

table).. Applications are sometimes submitted to the Mijnwet (the same law applied to shale gas 

exploration) when extraction takes place below 500 meters. Developing frack fluid formulations that 

can utilize water with higher chloride levels would decrease the use of fresh water 

Figure 4-10. Representation of water zones 

4.3.1.4 Surface water 

The general policy for the management of surface water is also defined in the Provincial Water Plan 

2010 – 2015. Water should contribute to a healthy environment for humans, animals and plants, where 

we can live safely, with space for economic, social and environmental developments. In order to achieve 

this goal, these nine different functions of surface water have been defined: 

1. Water nature 

2. Interwoven streams 

3. Ecological corridors along streams 


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4. Shipping 

5. Bathing 

6. Water for the National Ecological Network (NEN) 

7. Water feature for the ‘green-blue jacket’ 

8. Water for rural areas 

9. Water in urban areas 

Figure 4-11. Surface water includes rivers and streams 

An entire chapter (10) in the Provincial Water Plan is dedicated to water quantity. When there is not 

enough water for agricultural or industrial use the following preference order is used: 

1. Diminish the water demand 

2. Better use of water within the region 

3. Supply of surface water outside the region 

4. Groundwater withdrawal 

Withdrawal of surface water requires a permit from the water board in conformance with the 

regulations in the ‘KEUR’ (Act of Water Boards). The water board will judge the permit request in 

relation to the functions referenced above as well as the amount of water available. 

The possibility for withdrawal and the available capacity of surface waters depend upon: 

· The potential for drought conditions, especially in summer months 

· Existing industrial user withdrawals from a particular surface water body 

· Competition for withdrawal with nature and agriculture 


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In the province of Noord Brabant, three Water Boards are responsible for daily operations regarding 

surface water quality and quantity. These are: 

• Water Board Aa en Maas (Eastern sector) 

• Water Board de Dommel (Middle sector) 

• Water Board Brabantse Delta (Western sector) 

Figure 4-12. Surface water in Noord-Brabant, including areas with water supply areas and discharge sewage water treatment 

installations. The pink colored circles indicate the capacity (Mm3/yr) of water discharged from each of these facilities 

The following areas in the Noord-Brabant province are less suitable: 

• Streams delivering water to vulnerable nature areas (large parts of Waterschap De Dommel, 

located in the middle sector of the province) 

• Areas with a natural water supply shortage. For example large parts of Waterschap Aa en Maas, 

and the northern part of Noord-Brabant (see Figure 4-12. Surface water in Noord-Brabant, 

including areas with water supply areas and discharge sewage water treatment installations. 

The pink colored circles indicate the capacity (Mm3/yr) of water discharged from each of these 

facilities). Intake from the Meuse Maas) River into the canals (eg Zuid-Willemsvaart) provides 

extra water to these regions. The intake arrangements are made between the Rijkswaterstaat 

and the Peel en Maasvallei Water Board. Additional withdrawal of water in this area is therefore 


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a delicate subject. 

• Discharge rates are low in the upper parts of streams located in the south of Noord-Brabant. 

The following areas in Noord-Brabant are more suitable: 

• Areas close to the Meuse River (northern border of the Province of North Brabant.) 

• Those streams with high discharges (eg. De Aa, De Dommel, Esschestroom, de Mark-Vliet) 

• Canals such as the Zuid-Willemsvaart en Wilhelminakanaal 

• Those streams with continuous discharge of sewage water treatment installations 

Withdrawals from the De Dommelstream, the Zuid-Willemsvaart and Wilhelminakanaal canals can 

require a permit. 

As a result of strict enforcement regulations, the quality of the surface water is rather good. For 

example, the effluent of waste water treatment plants in most cases has a low concentration of 

phosphate (P) and Nitrogen (N), because additional treatment steps are taken to prevent algae bloom 

and other ecological purposes. 

Surface waters could be a source water if: 

• The streams have sufficient capacity and low ecological value. However, many surface waters 

are considered ‘no-go’ areas. 

• A permit for withdrawal of surface water is not a year-long guarantee. During droughts water 

boards are allowed to enforce a zero intake of surface water. Quality of the surface water is 

rather good, but not free of pathogens etc. This is due to discharge from waste water treatment 

plants. Detailed information is not yet available. The quality will be at least as good as the 

effluent of the WWTP. 

The costs for surface water are determined by permit fees. 

4.3.2 Surface Water Withdrawal Restrictions 

During the summer of 2011, several water boards placed water withdrawal restrictions due to drought 

conditions: 

· On 20 May, the Aa and Maas Water Board announced a ban on intake from surface water for 

the entire Raam district. 

· On 24 May, the De Dommel Water Board announced a ban on intake from surface water for 

almost all rivers and streams. Exceptions were granted for the Zandleij (with discharge from 

sewage water treatment, upper steam of De Dommel and Wilhelminakalnaal 

· On 19 May, the Brabantse Delta Water Board announced a ban on intake from the following 

areas: 

o Bijloop, de Oude Bijloop, de Turfvaart (nr 9) 

o de Kibbelvaart, Lokkervaart, Bosloop (nr 11) 


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o de Zoom and de Bleekloop (nr 15) 

· On 9 June, the ban was extended to the area de WouwseGronden (nr 13) 

Prior to making a long-term investment into the infrastructure required to use surface water as a water 

source for the development of shale gas, the potential limitations on reliable water withdrawals 

warrants further investigation. 

Figure 4-13. Area of the De Dommel Water Board, including the location of WWTP facilities: 1) Boxtel WWTP, 5) Tilburg 

WWTP, 6) Eindhoven WWTP, 7) Hapert WWTP, 9) Biest-Houtakker WWTP, 10) Haaren WWTP, 11) Sint-Oedenrode WWTP 

The capacities of each of these facilities are shown in Table 4-3. 

4.3.3 Wastewater Treatment Plant Effluent 

Water Boards are also responsible for management and operation of Waste Water Treatment Plants 

(WWTP). The WWTPs are summarized in Table 4-3, which includes quality figures about the maximum 


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concentration of Chemical Oxygen Demand (COD), Biological Oxygen Demand (BOD), N-Total, P-Total 

and suspended solids. The concentration of E-Coli per WWTP is unknown and would need to verified, 

but probably ranges from 5,000 to 400,000 units per ml. 

Effluent from a WWTP with pipelines being used to transport the water could be a possible provider of 

source water for shale gas development in the Netherlands. In most cases the location of the WWTP is 

not the same as the discharge point and the exact location of all discharge points has not been 

determined. 

Use of WWT effluent could be limited during the summer as the effluent may be the only re-charge 

source of some surface waters. The potential to use the effluent for fracking operations would be 

temporarily restricted during drought conditions. 

Information about the available capacities of WWTPs in Zone 8C can be found in Table 4-3. Subject to 

verification with the various water boards, this water could be used if the required capacity is below 

20% of the dry weather discharge requirements. 

Figure 4-14. Waste water treatment plant 

The cost of water is determined by permit fees and possible price per m3. The prices for WWTP effluent 

water would be significantly less than the price of drinking water. It is also important to note that this 

effluent water may require additional pre-treatment with biocides prior to being suitable for use in 

fracking operations. 


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Table 4-3. Information about WWTP 


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4.3.4 Summary of Availability and Costs of Water 

In zone 8C the drinking water, surface water and WWTP effluent sources present capacities that would 

cover required volumes of water. However, it is the question to what extent each of these sources will 

be actually available. Only after checking with Brabant Water (drinking water) and Water Board De 

Dommel (surface water and WWTP effluent) the actual capacities will be known. These numbers are 

required to be able: 

1. To quantify the total available water capacity in time. 

2. To determine the flexibility in covering the high and low fracking water demands in time per 

location in the area. 

Although it is expected that the quality of the surface water and WWTP effluent will satisfy the quality 

for fracking water, several water quality parameters such calcium, magnesium, alkalinity, are unknown. 

These data will have to be collected. 

Prices for surface water and WWTP effluent are to be determined by the Water Board and will be 

determined based on the permit and the price per m3. These are not known to date. However, it is 

expected that the prices of both surface water and WWTP effluent will be well below the price of 

drinking water. 

4.3.5 Water Chemistry 

An understanding of the ambient ground and surface water chemistry composition in the vicinity of the 

potential drill sites as well as the extent, depth and connections of the local fresh water aquifers to the 

surface water discharge points are essential components in the development of a Comprehensive Water 

Management Plan for any drilling project. There are several stages of a development project in which 

additional information is required. 

For any drilling project Water Management Plans must not only satisfy regulatory requirements, but 

also prepare the operator to address public perception issues. Prior to drilling, the consideration of 

depth and extent of the fresh water aquifer always influences the surface casing design, but the predrilling 

planning should also consider background aquifer and surface water composition as part of the 

site preparation costs. 

Drilling projects are scrutinized for the potential to contaminate ground and surface water supplies; 

therefore, it is important to establish the background conditions in the hydrologic system for 

comparison. A comprehensive water management approach can confirm correct and safe operations. 


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Figure 4-15. Geochemical data analysis 

4.3.6 Regional Data 

The hydrochemical characterization should consider the following water occurrences, locations, 

hydrologic relevance to the drill site and chemical compositions. Much of the data needed resides in 

institutional databases maintained by federal or regional agencies or geological society documents. 

• All surface water bodies (lakes, reservoirs, rivers and streams) 

• Existing groundwater wells (public and private) 

• Water disposal wells 

• Industrial water users and their discharge permits 

• Identified contaminated sites and their impact upon the aquifers 

• Locations of other rig supply wells (current and historic) 

• Active or abandoned reserve pits 

• Existing chemical and isotopic composition or dissolved hydrocarbon gases, inorganic dissolved 

constituents, detected organic constituents, and analysis of components that could be used as 

frac fluid markers 

Having this baseline of data and maps, the operator will know what if any additional regional data are 

needed to the drill site specific data collection that is done prior to drilling. 


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4.3.7 Drill Site Data 

A drill site specific sampling program should be designed to assess the existing status of surface and 

ground water within a specific distance from the drill site. Usually, the sampling of two to three wells 

within 0.4 to 0.8 kilometers is sufficient; preferably the samples would be collected in different 

directions. Analyses should include those required by governing regulations, but also need to include 

component and isotopic identification of dissolved hydrocarbon gases, dissolved inorganics and frac 

fluid markers from samples collected in a timely manner from domestic or other wells near the drill site. 

If there are any water wells that do not have reliable analytical data, it is recommended that samples be 

collected and analyzed to be included in the baseline database. This drill site specific sampling must be 

done both pre and post-frac operations. 

4.3.8 Aquifer Definition 

The connection between the regional data, the sampled wells and the drill site is most importantly 

defined by the aquifer continuity. Current aquifer modeling capabilities allow for the rapid construction 

of visualization models of the aquifers, wells, surface features, and boundaries, from which cross 

sections can be quickly constructed. This gives the operator the ability to assure that the data are 

related to the drill site, provides an interpretive tool, and serves as a method to quickly and effectively 

describe the hydrologic circumstances to management or regulatory agencies. 


156


Figure 4-16. Aquifer modeling 

The information required to effectively create the 3D geologic model of the aquifers is typically 

obtainable by reviewing several sources of publicly available information such as drilling logs from water 

well drilling contractors, previous studies performed by governmental agencies and water boards. 

4.3.9 Long term 

The summary of the hydrogeochemical program has its contribution during ongoing operations, but also 

provides the operator with a database and proprietary set of reports that serve as a bench mark for any 

future needed work. It would also be advantageous for continuity to use a single firm to design the 

hydrogeochemical program, manage the sampling and analysis and perform the modeling. 

4.3.10 Water Treatment 

Shale gas well development activity generally requires the use of considerable quantities of water, 

particularly for hydraulic fracturing. 

Effective treatment management of shale gas flowback and produced water requires some level of 

knowledge of the characteristics of the water. Flowback and produced water contain salts, metals and 

organic compounds from the formation and the compounds that are introduced as additives to the 

influent hydraulic fracture (frac) stream. Discussions between Operators and regulatory agencies in gas 

shale plays have led to the need for an information base on the composition and properties of flowback 

and produced water. 

During a typical hydraulic fracture well completion, water is pumped downhole while additives such as 

friction reducers and various grades of sand are introduced to ensure a successful fracture and 

completion of the shale. Following hydraulic fracturing, a fraction of the water (approximately 15% to 

25%) that was injected is collected over several days resulting in the collection of a “flowback” water 

stream that contains salts, oils and greases, and soluble organics (volatile and semi-volatile) that 

accumulated in the water downhole. Flowback water also contains low concentrations of additives that 

are introduced during the frac job which normally include friction reducing polymers, corrosion 

inhibitors, scale inhibitors, and biocides. These additives facilitate the hydraulic fracturing process and 

prevent problems with well operation. Listed below are tables which show the chemical composition 

for major chemicals in flowback and produced water in the Marcellus shale gas play in the United States. 


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Table 4-4 Flowback Water Chemical Composition – usually collected from Day 1 through 30 after a hydraulic fracture event. 

Concentration (mg/l) 

Marcellus - Pennsylvania 

TDS 90,000 -120,000 

TSS 100 --210 

Fe 50 - 125 

Mg 125 - 200 

Ba 500 - 2,000 

Sr 400 - 1,020 

Cl 54,000 - 75,000 

Sulfates 4 - 110 

Specific Gravity 1.1 

pH 6.5 - 7.2 

Table 4-5. Produced Water Chemical Composition 

Concentration (mg/l) Marcellus - Pennsylvania 

TDS 150,000 - 300,000 

TSS 150 - 400 

Fe 70 - 300 

Mg 515 - 1,710 

Ba 500 - 2,030 

Sr 400 - 2,520 

Cl 105,000 - 210,000 

Sulfates 10 - 250 

Specific Gravity 1.1 

pH 6.5 - 7.2 

As with conventional produced water, shale gas flowback water cations are dominated by sodium and 

calcium; the main anion is chloride. Metals normally seen in conventional produced waters, such as 

iron, calcium, magnesium, and boron, are at levels in flowback waters that are well within known ranges 

for normal produced waters. Heavy metals that are of concern in urban industrial wastewaters and 

POTW sludges --- such as chromium, copper, nickel, zinc, cadmium, lead, arsenic and mercury --- are at 

very low levels. 


158


Figure 4-17. Fresh water knock-out separator and produced water storage tanks 

Among flowback and produced water volatile organic constituents (VOCs), approximately 96% of the 

constituent determinations were at non-detectable levels and less than 0.5% were detected above 1 

mg/l. VOCs that are measurable are those that are normally found in conventional produced waters. 

Regarding semi-volatile organic constituents (SVOCs), more than 98% of the determinations are at nondetectable 

levels and less than 0.03% of all the constituents were above 1 mg/l; and several constituents 

were at low trace levels (information provided by Marcellus Shale Coalition). 

Naturally occurring radioactive materials (NORM), such as radium, are mobilized from the oil or gas 

formations because of the solubility in the presence of chloride ions which are present in the water 

within formation. Low solubility of the sulfate species is a factor in re-deposition of NORM. The low 

solubility precipitates scale containing high concentrations of radium in the form of barium sulfate or 

barite under the effects of varying temperature and pressure during the production operations. 

4.3.11 Treatment Technologies and Approaches 

Operators in the United States shale gas plays are recycling almost all of the flowback and produced 

water generated during well completion operations by blending it with fresh water and reusing the 

combined water as hydraulic fracture water in another well. Operators are taking the following 

approach when recycling and disposing of flowback and produced water: 

• Blend flowback and produced water with fresh water to reduce chemical concentration 

levels. 

• Add friction reducers, anti scalants and biocides for hydraulic fracture water makeup 


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• Utilizing mobile water treatment technologies to remove or reduce certain constituents that 

cause scaling and fouling with well completions. 

• Transport flowback water to permitted central treatment facilities for recycle or treatment 

prior to effluent discharge to permitted surface water sources. 

• Transport flow back and produce water for permitted brine well disposal (discussed in 

section below). 

The level of flowback/produced water treatment varies depending on the required flowback and 

produced water quality, fresh water quality and the proportion of each in the hydraulic fracture water 

blend. Operators are taking a stepped approach when they treat flowback and produced water for TSS, 

bacteria, Fe, Mg, Sr, Ba and TDS removal. Each Operator has their own specification for makeup of 

hydraulic fracture fluid. Most want to remove scaling chemicals which impact well production and 

equipment/piping maintenance. 

Figure 4-18. Reverse osmosis (RO) water treatment equipment 

Various flowback and produced water treatment technologies are available to the oil and gas industry. 

There are many treatment suppliers offering their technology treating flowback and produced water. 


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The treatment options can differ in their inherent capability, setup facility requirements, capital costs, 

operating expense, and waste (sludge and brine concentrate) streams; all these factors can be important 

to the gas Operator. 

Some treatment technologies may have large space requirements that may not be possible in some gas 

well installations. Some technologies may be commercially available as small, skid-mounted mobile easy 

to move around units that easily can be relocated as production conditions change. Equipment costs 

are important in some installations where a large amount of dedicated equipment must be purchased 

for managing flowback and produced water. 

This section below describes various produced water technologies along with examples of how they are 

being implemented in the field. 

Bag Filtration – Bag filters are currently being used by Operators for removal of TSS from flowback and 

produced water before recycle. Spent filtrations bags are being disposed of at permitted landfills. 

Figure 4-19. Removal of total suspended solids (TSS) 

Physical/Chemical Separation – Some Operators are adding chemical reagents to react with dissolved 

heavy metals (Fe and Mg) to form insoluble hydroxide-based precipitates that can be removed with 

other suspended solids from the wastewater stream using clarification and/or filtration. Also the 

addition of other chemical reagents to react with barium and strontium to form sulfate-based 

precipitates that can be removed with other suspended solids from the wastewater stream using 

clarification and/or filtration. 


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Figure 4-20. Physical / Chemical separation equipment 

Lamella Gravity Clarification/Flotation – Clarification is one of the most popular and proven processes 

used by Operators used to treat” contaminants, mainly TSS, for removal in flowback and produced 

water. While some systems settle solids out of the liquid stream by gravity, others use flotation 

methods to float the solids to the top to be skimmed away. 

Figure 4-21. Representation of on-site water treatment equipment 

Activated Carbon Filtration – Operators are currently using activated carbon filters to remove bacteria 

from flowback and produced water before the treated water is blended with fresh water for recycling. 


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Figure 4-22. Activated carbon filtration equipment 

Advanced Oxidation - This treatment approach utilized by some Operators may also include chemical 

oxidation such as ozone treatment to reduce dissolved hydrocarbons from natural sources and residual 

hydraulic water conditioning reagents. 


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Figure 4-23. Mobile advanced oxidation trailer 

Electro coagulation – This process destabilizes and coagulates the suspended colloidal matter in 

flowback and produced water. When contaminated water passes through the electrocoagulation cells, 

the anodic process releases positively charged ions, which bind onto the negatively charged colloidal 

particles in water resulting in coagulation. At the same time, gas bubbles produced at the cathode, 

attach to the coagulated matter causing it to float to the surface where it is removed by a surface 

skimmer. Heavier coagulants sink to the bottom, leaving clear water, suitable for use in drilling and 

production operations. 


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Figure 4-24. Skid-mounted electro coagulation equipment 

Sludge Dewatering – Plate and frame filter presses are currently being used by some Operators for 

dewatering of sludge from clarification and sludge thickening treatment steps. The sludge cake material 

is being disposed at permitted landfills and tested for NORM detection levels. 

Figure 4-25. Filter press equipment used to de-water sludge 

Reverse Osmosis – This process of removing salts (TDS removal) from flow backwater uses a membrane. 

With reverse osmosis, the product water passes through a fine membrane that the salts are unable to 

pass through, while the salt waste (brine) is removed and disposed. This process differs from 

electrodialysis, where the salts are extracted from the feedwater by using a membrane with an electrical 

current to separate the ions. The positive ions go through one membrane, while the negative ions flow 


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through a different membrane, leaving the end product of freshwater. This treatment is only capable of 

treating water containing TDS up to 30,000 to 40,000 mg/l. 

Figure 4-26. RO filter racks 

Mechanical Evaporation - Due to the relatively high TDS concentrations in flowback and produced water 

in United States shale gas plays, the only feasible demineralization option for Operators, is mechanical 

evaporation, which uses pressure and high temperature to remove water vapor from the wastewater 

stream. The recovered distillate, which is typically 50 to 65% of the influent stream, is of very high 

quality that can be reused as fresh makeup water. The TDS present in the wastewater is collected in a 

concentrated brine reject stream, which can be converted to salt cake in a crystallization process or 

disposed by deep well injection. 


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Figure 4-27. Trailer mounted mechanical evaporation equipment 

Crystallization – Brine concentrate can be further processed in the crystallization process and yield 98% 

recovery of water distillate. A residual salt (mostly sodium chloride and calcium chloride) is generated 

from this process which can be reused or disposed of at a permitted landfill. 

Figure 4-28. Crystallization towers 


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Some flowback and produced water treatment suppliers in US shale gas plays are progressing into 

developing modular fixed-based treatment facilities that can be assembled within well fields, and when 

the well fields are completed, the treatment facilities are disassembled and relocated to new well fields. 

This arrangement will result in lower flowback and produced water transportation costs and reduce 

impacts to local roads. 

Another related design approach being developed by Operators in the US is to lay out a “hub and spoke” 

gas and water pipeline network within a well field where natural gas is conveyed to a centralized 

compressor station complex and then piped to the transmission pipeline. Where the water pipelines 

run parallel to the gas pipelines, flowback water is pumped to centralized impoundments, treated, 

blended with fresh water, and returned to the well pads. The gas and water pipelines are located in the 

same trench to reduce construction costs while impacts are significantly reduced. This results in 

significant cost savings for the Operators charged for road maintenance and repair costs by local 

government. 

Table 4-6. Treatment Technology 

Treatment Technology 

Bag Filtration 

Physical/Chemical Separation 

Activated Carbon Filtration 

Advanced Oxidation 

Electrocoagulation 

Sludge Dewatering 

Reverse Osmosis 

Evaporation 

Crystallization 

Removes 

TSS 

TSS, metals, Ba, Sr 

Bacteria, TSS 

Metals 

Metals and some TDS 

Dewaters sludge 

TSS (lower concentration) 

Removes TSS, metals, TDS and bacteria 

Removes TDS from brine concentrate 

4.3.12 Conclusion 

Flowback and produced water treatment technologies convert poor quality produced water into good 

quality water by removing contaminants and impurities. For Operators that are considering large scale 

of flowback and produced water treatment facilities, the amount of waste volume needs to be 

considered when planning for these water treatment facilities and/or mobile treatment systems. The 

selection of a flowback and produced water treatment and recycle system depends on several factors 

such as the Operator’s drilling plan/schedule, and hydraulic water fracture chemistry requirements. 


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4.3.13 Beneficial Re-use 

We considered that the produced water from the shale gas development activities could be put to 

some beneficial re-use. This is an area of considerable research 

The produced waters derived during the extraction process contain various compositions of naturally 

occurring formation and injected chemicals and must be analyzed to determine their chemical 

composition. Typical produced waters will contain traces of hydrocarbons, dissolved organics, organic 

acids, phenols, production chemicals and inorganic compounds such as varying amounts of chlorides, 

sulfides, bicarbonates, ammonia phenolic compounds, metals and suspended solids. 

In order to consider the re-use of these waters, certain basic treatment technologies must be employed 

in order to reduce their chemical composition down to acceptable levels. 

There are a number of potentially viable options for re-use of these produced waters including: 

• Oil & gas operations 

o Water floods for well stimulation 

• Agricultural operations 

o Livestock watering 

o Wildlife watering and habitat 

o Irrigation of crops 

• Recreational waters 

o Fishing 

o Water sports 

o Constructed wetlands 

• Drinking water aquifer restoration 

• Industrial uses 

o Process waters 

o Cooling towers 

o Power generation 

• Dust control 

• Fire control 

This concept of beneficial re-use of these produced waters will require further thorough research. 


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Figure 4-29. Treated waters can be re-used for agricultural irrigation 

4.3.14 Disposal Options 

Through the implementation of the Water framework Directive (WFD), the Water Act (Waterwet) 

regulation has changed since 2009. In addition to materials and/or emissions, the permit must pay 

attention to other environmental impacts, including ecology. As elaborated in the water management 

plans, the criteria and principles of the WFD, should be used. An assessment framework has been 

developed to help the local Water BoardsThe effluent need to meet the requirements of very low 

concentrations regarding metals, biocides, and salt. 

The possibilities for disposal of produced waters from drilling operations are: 

• Waste water treatment plant (WWTP), transported directly or indirectly through a sewer pipe 

• Into surface waters 

• Injection into an aquifer 

• Injection into an depleted oil or gas well 

• Transport by truck to a dedicated treatment facility (Waste Terminal Moerduijk (ATM) or Waste 

Treatment Rijnmond (AVR)) 


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Legislation in the Netherlands concerning the quality of discharge water is strict with the levels of 

chemicals, biocides, metals and salt being the primary areas of concern. 

Actual cubic meter prices depend on: 

· Capacity, 

· Quality, 

· Distance, 

· And the period of water discharge. 

4.3.14.1 WWTP 

All production and waste water must be pre-treated to remove biocides and metals and reduce salt 

levels prior to entering the WWTP system to ensure these waters do not impact the treatment 

processes which are primarily biological. Produced and flowback water must be carried via a dedicated 

pipeline. 

Figure 4-30. WWTPs are limited in their ability to process frac waters 

While the WWTP process does not remove the salt, if the treated water still has a high salt 

concentration, additional treatment will be necessary. The maximum allowable concentration of salt is 

within a 150 to 500 mg/l range, and is dependent upon where the water will be discharged. 

4.3.14.2 Surface water 

Discharge to surface water is only possible if the effluent meets the very tight maximum allowable 

concentrations for metals, P, N, COD, BOD etc. The same maximum allowable concentrations are 


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applicable in the case of direct discharge to surface water. The maximum allowable concentration of 

salt is also within the range of 150 to 500 mg/l, and also dependent upon where the water will be 

discharged. 

Operator needs to obtain a license to discharge surface water, which will require the water treated to 

near drinking water quality. 

4.3.14.3 Re-injection of Water 

One of the most common disposal methods is the re-injection of these waters back into geological 

formations. There are a variety of considerations which must be taken into account prior to re-injection. 

Geological formations must be evaluated to determine injection rates, in order to ascertain whether reinjecting 

the water is economically and ecologically viable. 

Geological conditions and formations must be evaluated within the proximity of the drilling operations 

in order to determine whether any potential salt caverns or depleted reservoirs are present, which can 

be used to store these waters effectively. 

Figure 4-31. Diagram of Injection Well 

4.3.14.4 Injection into an aquifer 

The legislation to infiltrate water is very stringent. In some cases, the maximum allowable 

concentrations are more stringent than for drinking water. In addition, local policies have been 

developed to preserve precious groundwater, as described in the Grondwaterwet / Infiltratiebesluit 

(Groundwater legislation). 


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4.3.14.5 Injection into a Depleted Oil / Gas Well 

In the Netherlands, water injection into depleted gas reservoirs is mainly performed by Dutch Oil 

Company (NAM). Injection first began in 1972 and since 1991 many studies have been conducted 

including LCA’s (Life Cycle Assessments) and EIA. Water injection into depleted gas reservoirs, both on 

and offshore is allowed. With respect to the legal framework, offshore injection is slightly different to 

injection onshore. Current legislation is based on conventional oil and gas production, including 

regularly used types of chemical additives. 

Unconventional gas production (e.g. shale gas) differs significantly in terms of type and concentrations 

of additives which becomes an important issue since an injection permit requires substantial and 

credible evidence that the (structural) integrity of the geological formation is not compromised. 

Currently, the Dutch legal framework for underground water injection consists of the following 

components. 

4.3.14.5.1 Mining aspects 

Mining Act, Mining Decree and Mining Regulation (eg. application for the use of chemical additives, is 

regulated by paragraph 9.2 ‘Use and discharge of chemicals’ of the Mining regulation). 

4.3.14.5.2 Environmental Aspects 

EU Directives 

· EU Directive on industrial emissions (integrated pollution prevention and control; 2010/75/EU): 

focuses on Best Available Techniques (BAT) and relevance in case of underground storage of 

hazardous waste with a total capacity exceeding 50 tonnes. 

· EU Directive on waste (2008/98/EU): Definition of ‘Disposal operation D3: Deep injection (eg. 

injection of pumpable discards into wells, salt domes, or naturally occurring repositories, etc.)’. 

· National Waste Management Plan. 

· In the Netherlands, the treatment of waste is regulated by the National Waste Management 

Plan (NWMP), which is part of the Environmental Management Act. An updated version of the 

NWMP was published for the period 2009 – 2021 and Chapter 21.17 of this regulation addresses 

onshore water injection. The NWMP is based on the principle that no substances can be 

injected, other than substances directly coming from a geological formation. Other relevant 

aspects are: 

· The European list of waste materials (Eural) is used to identify the stream of water as hazardous 

or non-hazardous. In case of conventional gas production, the injection stream is classified as 

non-hazardous. 

· Water injection protocol – this protocol provides guidelines to assess the impact of water 

injection. The terms of the NWMP are met by applying this protocol. 


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· EIA: depending on water quality and quantity, an EIA-procedure is required. The terms and 

conditions have been altered recently, resulting in a discussion about whether or not all new 

water injection initiatives require a full EIA procedure. 

The NWMP is less relevant in the case of offshore injection, although the OSPAR Convention, London 

Protocol, and national studies by the Commission of Integral Water management (CIW), have to be 

taken into account. Furthermore, several studies which make a comparison between water injection 

and a purification process based on costs, environmental impact (LCA), operational risks, and long-term 

risks, are available. 

4.3.14.6 Transport by Truck to a Dedicated Treatment Facility 

Some dedicated treatment facilities are present in the Netherlands. These are the ATM in Moerdijk and 

AVR near Rotterdam. If the effluent is ‘transported’ by truck, the main issue will be the number of truck 

movements (cost and environmental impact). Therefore the volume of water to be discharged has to be 

reduced. Depending of the volume of water, some kind of treatment is necessary. If it is of good 

quality, the filtrate can be reused and discharged into the sewerage system, assuming all metals, 

biocides, salt etc. are concentrated in the brine. 

Figure 4-32. Truck hauling produced water to an off-site disposal facility 


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4.3.15 Conclusion 

Further recommendations on water disposal options can be made once field development plan is drawn 

up. This plan should confirm the number of wells to be drilled, contain a drilling schedule, plus further 

information about water chemistry, volumes of flowback, and produced water. 

4.4 General Environmental and HSE Management 

4.4.1 General Environmental - Air Quality 

The impact of emissions on local air quality is regulated by the Environmental Management Act (Dutch: 

“Wet Milieubeheer”). Chapter 5 of this act deals with air quality and facilitates a so called ‘flexible link’ 

between spatial development regulation and air quality regulation by programs to improve air quality in 

certain regions of the Netherlands. The definition of ‘significant impact' is introduced here to indicate 

whether a project has a significant impact on air quality. 

The law distinguishes between large and small projects based on their environmental impact. The 

impact of a project is classified as being ‘not significant’ if the calculated concentration (annual average) 

related to the project is smaller than 3% of the air quality limit value for Nitrite (NO2) and Particulate 

Matter-10 (PM10) (3% equals 1,2 µg/m3). Projects that do not have a significant impact can be 

achieved. 

However, the proximity to a Natura2000 area can introduce additional constraints on emissions of NO2. 

Within the European Union, the Netherlands is the only EU Member State that applies critical deposition 

values as a reference for the evaluation of a 'significant effect'. The main reason for this is that 

deposition of nitrogen causes over-fertilization. In Noord-Brabant nitrogen deposition is mainly caused 

by a combination of large scale agricultural activities, and to a lesser extent, industries. 

4.4.1.1 Relevant Emissions for Shale Gas Production 

Emissions that relate to the production of shale gas, could potentially originate from the following 

sources: 

• Combustion emissions from trucks and drilling equipment; 

• Combustion emissions from stationary heat or power generation; 

• Emissions from natural gas processing and transportation; 

• Evaporative emissions from waste water ponds; 

• Emissions due to spills (dispersion of drilling or fracturing fluids combined with PM from the 

deposit). 

The relevant guidelines per emission source are presented for the Dutch situation in the table below. 


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Table 4-7. Relevant Emission Guidelines 

Emission source 

Stationary heat or power generation 

Evaporative emissions from waste water ponds 

Emissions from natural gas processing and 

transportation 

Trucks 

Guidelines / Directives 

Act on Emissions for medium sized heat generation 

equipment (BEMS) or Directive 2001/80/EC for Large 

Combustion Plants >50 MW(LCP) 

Dutch Emission Guidance (NeR) 

Best Available Technology (IPPC) 

EU Directive 05/55/EC 

Drilling equipment 

EU Directive 97/68/EC on emissions of gaseous and 

particulate pollutants from engines in Non-Road Mobile 

Machinery (NRMM) 

4.4.1.2 Integrated Pollution Prevention Control (IPPC) Directive 

The IPPC Directive concerning integrated pollution prevention and control sets out the main principles 

for permitting and control of installations. This is based on an integrated approach and the application 

of Best Available Techniques (BAT). These ‘best available techniques’ are the most effective way to 

achieve a high level of environmental protection, taking into account costs and benefits. For a selection 

of activities, the best available techniques are defined in Reference documents (called “BREF’s”), an 

important aspect of obtaining an environmental permit. 

The IPPC Directive and sectorial Directives will be replaced by the Directive on Industrial Emissions 

2010/75/EU (IED) as of 7 January 2013. The Directive on Industrial Emissions 2010/75/EU (IED) came 

into force on 6 January 2011 and has to be transposed into national legislation by Member States, by 7 

January 2013. In this new IED the concept of BAT provisions will be strengthened, and mandatory 

emission limit values for existing plants will become more stringent. 

According to the IPPC Directive (and eventually the IED), application of BAT is mandatory when the 

activity is defined in annex I of the Directive. In addition to this European Directive, The Netherlands 

assessed BREF documents and defined more specific requirements applicable in the Dutch context. The 

results of this assessment are laid down in so called resolutions (Dutch: ‘oplegnotities’) which should be 

considered for permit applications. The resolution for gas refineries is incorporated in the Dutch 

Emission Guideline (Dutch: NeR). 

For shale gas development, the following BREF documents may be relevant: 

• Reference document on BAT for Mineral Oil and Gas Refineries. In the scoping section of this 

document, the following activities are included: 


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o 

o 

#17 Natural gas plants: Processes related with the processing of natural gas 

#20 Product treatments: Sweetening and final product treatments 

4.4.1.3 Non-Road Mobile Machinery 

NRMM covers a large range of engine installations in machines used for purposes other than for 

passengers or for the transportation of goods. Diesel and spark emission engines installed in NRMM, 

such as gas compressors, water pumps, industrial drilling rigs, bulldozers, etc., contribute to air pollution 

by emitting carbonous oxides (CO), hydrocarbons (HC), nitrogen oxides (NOx) and PM. 

Figure 4-33. Non-road construction equipment 

Emissions from these engines are regulated by four directives before they are placed on the market. 

These are: Directive 97/68/EC; amended by the Directive 2002/88/EC and by the Directive 2004/26/EC. 

For the various types of NRMM, the Directive stipulates the maximum permitted exhaust emissions as a 

function of the power of the relevant engine. Moreover, the Directive includes a series of emission limit 

stages of increasing stringency, with corresponding compliance dates. Manufacturers must ensure new 

engines comply with these limits so they can be placed on the market. 

4.4.1.4 Stationary Heat or Power Generation 

Combustion emissions to air (such as PM, Sulphur dioxide (SO2), Nitrates (Nox), and CO, for instance) 

that emit from stationary heat or power generation installations, are subject to either the Dutch 

‘Besluitemissie-eisenmiddelgrotestookinstallaties’ (shortly to become BEMS) for smaller installations, or 

to the European Large Combustion Plants Directive 2001/80/EC (LCP), when the rated thermal input 

exceeds 50 Mega Watt (MW). Emission limits for both BEMS and LCP vary based on capacity and age of 


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the installations. In the near future, the LCP directive will be integrated with six other directives in the 

IED, (see also IPPC Directive). 

Based on actual available information on shale gas production, it is not expected that thermal input will 

exceed 50 MW. 

Figure 4-34. Diesel-fired generator 

4.4.1.5 NMVOC Emission Limits 

Emission limits for both fugitive and process emissions (such as Volatile Organic Carbons(VOC) and 

benzene (BZ) are derived from the Dutch Emission Guideline in the environmental permit (Dutch: 

Nederlands emissie richtlijn lucht (NeR)). For instance, for process emissions of benzene, the NeR is 

applicable if more than 2.5 grams per hour are emitted. The emission limit for BZ is then 1 mg/m3. 

Controlling fugitive emissions of process installations is described in the protocol ‘Measurement 

protocol diffuse emissions’ (Dutch: ‘Meetprotocolvoorlekverliezen’). The obligation to measure fugitive 

emissions is incorporated in the environmental permit. 

4.4.1.6 Trucks 

European emission regulations for new heavy-duty diesel engines are commonly referred to as Euro I to 

Euro VI. Manufacturers of trucks must ensure that new engines comply with these Euro emission 

standards, so that they can be placed on the European market. Euro classification depends on the 

emission standards of CO, HC, NMVOC, Methane (CH4), NOx, PM and Smoke. 


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4.4.1.7 Emissions Trading 

Greenhouse Gas Emissions: The operation of power and heat generation, or drilling equipment, 

consumes fuels which are burnt to emit CO2. Any fugitive emissions of greenhouse gases that might 

occur during production, processing and transport of the natural gas. The European CO2-emissions 

trading scheme (EU ETS), is applicable to stationary emission sources with a total permitted capacity 

over 20 MW thermal. 

NOx: If the total capacity of stationary combustion installations exceeds 25 MW thermal, the Dutch NOx 

emissions trading scheme may be applicable. 

4.4.2 General Environmental - Noise 

Regulations make a difference in direct noise, indirect noise, and vibrations. Research of Noise and 

vibrations need to be studied at both the exploration and production phases. When researching 

exploration and production noise levels, there would be a distinction between average and peak noise 

levels. 

In general all regulated emissions concerning noise and vibration levels on residential, medical or 

educational buildings are required to be studied. These buildings are protected against high noise levels 

by laws, regulations and standards. 

Due to the proximity of residential or business areas, the Operator will install noise barriers to limit 

disturbance to neighbors. Installation of these barriers can be for temporary use during construction and 

drilling phases. Some facilities that house processing equipment and/or compressors on-site, may build 

permanent noise suppression techniques and materials into their design. 


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Figure 4-35. Noise barriers are constructed to limit noise levels during construction activities 

4.4.2.1 Direct Noise - Construction Phase 

There is no noise regulation in environmental laws for the judgment of noise nuisance resulting from 

construction activities. Noise nuisance can be regulated in permits according to local laws or regulations. 

It is possible that a national law will come into being that will regulate construction noise. Generally in 

all cases, (and also with the new law), guidelines for construction noise are used to prove that noise 

nuisance meets the requirements, according to Circulaire Bouwlawaai 2010. The framework for 

construction noise levels measured in decibels (dB (A) is: 

Table 4-8. Caption 

Day period 

07.00-19.00 

Maximal exposure 

time in days 

Up to 

60 dB(A) 

Above 

60 dB(A) 

Above 

65 dB(A) 

Above 

70 dB(A) 

Above 

75 dB(A) 

Above 

80 dB(A) 

No restrictions in Max - 50 days Max - 30 days Max -15 days Max - 5 days 0 days 

days 

For construction works outside the day period, custom requirements are required in consultation with 

authorities. 


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Figure 4-36. Drilling rig with noise barrier 

4.4.2.2 Direct Noise - Production Phase 

There are no noise regulations under environmental laws for judgments concerning noise nuisance in 

surroundings situated near industrial activities. Noise nuisance is regulated in the permit of the 

surroundings (Omgevingsvergunning). According to article 5.3, Besluitomgevingsrecht (Bor)’ which uses 

a general description for noise nuisance: ‘Regulations and measures are needed to prevent negative 

effects from industrial activities to the environment, and the effects are limited and or prevented at the 

source of the noise’. 

The permit is granted by the Provincial Executive of North Brabant. The Provincial Executive will judge 

whether noise nuisance in the direct surroundings of the industrial activities is acceptable. 

The framework for the judgement is the regulation for industrial noise and permitting 

‘Handreikingindustrielawaai en vergunningverlening’ 1998. The main points of interest in this regulation 

are mentioned below. 

The necessary permits will define the noise levels on buildings (residential, medical, education), for the 

representative operating conditions during the day, evening and night period. The permits for noise 

consist of reports where calculations are based on predictions and measurements. 


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Table 4-9. Noise Levels in Urban Areas 

Periods 

Maximum accepted average noise 

levels (L Aeq ) on buildings (residential, 

medical, education) 

Day - 07.00-19.00 50 dB(A) 70 dB(A) 

Evening - 19.00-23.00 45 dB(A) 65 dB(A) 

Night - 23.00-07.00 40 dB(A) 60 dB(A) 

Maximum accepted peak noise levels (Lmax) 

on buildings (residential, medical, education) 

The noise levels mentioned above are noise levels that are generally accepted within in a standard 

urban environment. In case of silent environment (nature), all accepted noise levels have to be lowered 

by 5 dB (A) or even 10 dB (A). 

In case of activities with tonal or impulse noise characteristics, the noise levels of these activities have to 

be raised by a 5 dB (A) penalty. 

4.4.2.3 Indirect Noise 

Noise from transportation movements, to and from the well pads, is regulated under ‘noise nuisance 

caused by traffic from and to the site and is judged at permit issuance under the Environmental 

Management Act” (‘Geluidhinderveroorzaakt door het wegverkeer van en naar de inrichting; 

beoordeling in het kader van de vergunningverlening op basis van de Wet milieubeheer'), 29 February 

1996. 

The bandwidth for acceptable average noise levels is between 50 dB(A) and 65 dB(A). Less than 50 dB(A) 

is preferred. Higher than 65 dB(A) is not allowed. 

4.4.2.4 Vibrations 

There are no vibration laws or regulations, but in this case it can be assumed that there will be vibration 

issues. This is required to determine the vibration impact on the surroundings for construction and 

production phases. 

Guidelines for vibrations are accepted in jurisprudence. The guidelines are from the Building Research 

Foundation (StichtingBouwresearch, SBR), Trillingen: meet- en beoordelingsrichtlijn - Deel A, B en C. 

4.4.2.5 Summary for Noise and Vibration Impacts 

According to cited regulations for noise and vibrations relative to shale gas development, the issues are: 

· Transport movements on the public road, relate to construction and production. High noise and 

vibration levels are not possible according to the regulations on indirect noise nuisance. 


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Pipelines instead of transportation movements will reduce the noise impact on nearby buildings. 

· Production (and possibly construction) works are 24 hours. The night period (23:00-07:00h) is 

normative for the acceptable noise levels on buildings. 

· These regulations are very tight for shale gas development in urban areas or with local 

residential/medical buildings nearby. 

· Vibration impact is not very well known and requires further research. 

Comparing the shale gas development with a general on-shore natural gas extraction area in the 

Netherlands, there are guidelines for the distance towards residential buildings: 

· For a gas extraction area with a gas treatment installation less than 10,000,000 m 3 /d, the 

indication of the minimal required distance is 500 meters. 

· For a gas extraction area with a gas treatment installation greater than 10,000,000 m 3 /d, the 

indication of the minimal required distance is 700 meters. 

· In most of the cases this means that a smaller distance makes it necessary to implement 

measures to reduce the noise levels. 

4.4.3 General Environmental - Lighting 

In the guideline of the Dutch association for Lighting (NSVV), a number of different visual effects are 

described that may lead to light pollution. One of these effects relates to direct incandescent light. The 

directive means by light incidence, especially there where light enters the rooms of houses, such as 

bedrooms, which are normally dark. As the parameter for determining this effect, vertical luminance is 

used at a point in a relevant surface (E y in lux): in homes usually vertical (façade) surfaces, especially 

windows. 

The exact value for the parameter mentioned below, which is based on no interference, depends on the 

surrounding original levels of existing light in the particular environment. The values in this table are 

referred to as threshold values; these are mainly determined by activities in the surrounding (industrial 

area, residential, rural area) and the possible presence of street lightning. The NSVV Guideline 

distinguishes four zones, as shown in the following table. 

Table 4-10. Existing Levels of Lighting 

Zone Description 

E1 Nature areas with very low ambient brightness 

E2 Areas with a low ambient brightness; in general outside urban and rural residential areas. 

E3 Areas with an average ambient brightness; in general residential areas. 

E4 Areas with high ambient brightness; in general urban areas, combined with residential and industrial 

areas with intense nocturnal activities. 


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For each zone threshold values can be formulated based on the table below (sports lightning). 

Table 4-11. Sports Lighting Levels 

Parameter Day period Surrounding area 

E1 

Nature area 

E2 

Rural area 

E3 

Residential 

E4 

City centre/ industrial area 

IL luminance (E v ) on 07:00 – 23:00 2 lux 5 lux 10 lux 25 lux 

facade 23:00 – 07:00 1 lux 1 lux 2 lux 4 lux 

I (cd) of each 

luminaire 

07:00 – 23:00 2.500 cd 7.500 cd 10.000 cd 25.000 cd 

23:00 – 07:00 0 cd 500 cd 1000 cd 2.500cd 

For each zone threshold values can be formulated based on the table below (public lightning). 

Table 4-12. Public Lighting Levels 

Parameter Day period Surrounding area 

E1 

Nature area 

E2 

Rural area 

E3 

Residential 

(S-class/MEclass) 

IL luminance (E v )on 07:00 – 23:00 5 lux 10 lux 10/20 lux 15/25 lux 

facade 23:00 – 07:00 1 lux 2 lux 5/10 lux 10 lux 

I (cd) of each 

luminaire 

E4 

City centre/ industrial area 

(S-class/ME-class) 

07:00 – 23:00 500 cd 500 cd 600/2500 1000/5000 cd 

23:00 – 07:00 500 cd 500 cd 600/2500 cd 2.500cd 


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Figure 4-37. Diesel-fired construction lighting trailer 

4.4.4 General Environmental - Summary 

For the notional feasibility study it is important to understand that any shale gas development program 

in the Netherlands must comply with Dutch regulations for air quality, noise and lighting. The 

cumulative emissions (all media) of all equipment used and activities performed during the exploration 

and completion phases of the project must be taken into account. Plans must be implemented to 

ensure that standards are met. 

The same is true for any production facilities that would be built to support the collection, processing, 

shipment and sales of shale gas within the Netherlands. The Dutch regulations must be the basis (as a 

minimum standard) for the engineering standards for any surface equipment and facilities. 

Any contractors brought on-site should be aware of the Dutch regulations and broader European 

standards for equipment being used throughout Europe. 


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The same would be true for the production operations. Once gas production volumes are most 

accurately projected, the engineering firm supporting this development project would use the Dutch 

regulations in their design basis. 

4.4.4.1 HSE Management – External Safety 

In the Netherlands, the Decree on External Safety of Establishments (Dutch: 

‘BesluitExterneVeiligheidInrichtingen’ also known as BEVI), aim to provide a minimum safety level for 

humans (primarily in buildings). To be able to determine the risk, all establishments that store and/or 

use hazardous substances (eg. chemical industries, refineries, chemical warehouses, tank storage 

facilities, oil and gas facilities, etc), need to prepare a Quantitative Risk Assessment (QRA). 

The results of such a QRA are expressed by means of two types of risk: 

· Individual Risk (IR): the likelihood per annum for an individual to be killed as a result of an 

accident (with hazardous substances) on the establishment. The IR is represented as risk 

contours (10 -4 per year, 10 -5 per year, 10 -6 per year, etc) on a map; 

· Societal Risk (SR): the likelihood per year for a group of people to lose their lives as the result of 

an accident, (with hazardous substances) on the establishment. 

In the Dutch QRA guideline (Dutch “HandleidingRisicoberekeningen BEVI” (HRB)), it is described in quite 

some detail which parts of the establishment should be included, what type of accident scenarios (eg. 

leakage or full rupture of a pipe or a vessel, blow out, etc.), failure frequency for equipment (tanks, 

piping, etc.) should be applied, etc. 

To be able to carry out the complex QRA-modelling, a mandatory computer model must be used (ie. the 

computer model Safeti-NL). All accident scenarios and type of substances, as well as characteristics of 

the surroundings, are given as input. The model will calculate the IR and SR. 

For the SR, BEVI provides general guidelines. For the IR, the BEVI contains quite detailed requirements, 

primarily with respect to the possibility of allowing buildings, where humans are or can be present 

(houses, hospitals, child care centers, hotels, offices, workshops, etc) within the IR contours: 

· Beyond the risk contour for 10 -6 per year (ie. a risk lower than 10 -6 per year) there are no 

limitations for existing areas that have been built upon. This includes housing and planned 

building developments, or for any other future developments; 

· Between the risk contour of 10 -5 and 10 -6 per year there are possibilities to allow for existing 

buildings, but new developments should be avoided; 

· Within the risk contour of10 -5 per year (ie. a risk higher than 10 -5 per year), in general no 

buildings are allowed. 


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For this conceptual field development, it is not yet possible to determine the IR and /or SR for the well 

pads, pipelines and central processing facility. Relevant IR contours can vary strongly and are dependent 

upon well pressure, casing size and length, number of wells, composition of gas and/or condensate, 

pipeline diameter and length, layout of process facilities, Emergency Shut Down (ESD) functionality, and 

other factors. Nevertheless there should be a certain distance between buildings and a well pad or a 

processing facility, up front. 

As a very rough initial estimate, a safety distance (for 10 -6 per year) of 200 meters between well pads 

and / or a processing facility could be suggested, but it needs to be emphasized strongly, that once the 

actual risk is being calculated, this distance may change significantly (positive or negative). 

Figure 4-38. Example risk contour (Source: Oranjewoud rapport "Onafhankelijk rapport schaliegaswinning in Nederland) 

4.4.4.2 HSE Management – Soil Protection 

To protect soil against new contamination resulting from operational businesses, the Dutch Soil 

Protection Guideline (Dutch “NederlandseRichtlijnBodembescherming”) has been issued. This Guideline 

is required for all companies in the Netherlands for which an environmental permit is required. 

4.4.4.2.1 Structure and Principles of the Guideline 

The Dutch Soil Protection Guideline states that all permitted activities need to result in negligible soil 

risk. This means that the license holder must prevent soil contamination as much as possible. To give 


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meaning to the term ‘as much as possible’, the Guideline offers multiple possible solutions for reaching 

a negligible soil risk for several different types of activities. All these solutions consist of two 

components: Soil protection provisions (impermeable barrier or retaining floors, drip pans, enclosed 

system designs, etc.) and measures (instructions to staff, spill kit use and maintenance, and inspection 

programs). Provisions and measures always need to be combined to reach a negligible soil risk. The 

more robust the facilities, the less tight measures are needed. This principle is illustrated in the Figure 

4-39. 

The guideline describes the different combinations for an activity. 

Figure 4-39. Example risk contour (Source: Oranjewoud rapport "Oranjewoud rapport schaliegaswinning in Nederland) 

4.4.4.2.2 Impact on Shale Gas Sites 

As shale gas drilling and production requires an environmental permit, the Dutch Soil Protection 

Guideline is applicable to all activities occurring on these sites. The following relevant questions need to 

be answered: 

1. Are the used substances a threat to soil quality according to the Guideline 

At shale gas drilling and production sites, the following substances are likely to be handled or 

stored: diesel (fuel for pump engines), fracking chemicals, fracturing fluid (dissolved fracking 

chemicals), drilling fluid, flow back water (containing chemicals and Naturally Occurring 

Radioactive Materials (NORM), lubricants for all kinds of operational equipment and shale gas. 

All other substances mentioned above are soil threatening according to the Guideline. 

2. Are the activities with soil threatening substances in need of any soil protective facilities and 

measures according to the Guideline 

The Guideline states that the following activities need a protective soil combination of 

provisions and measures: storage in underground or above ground tanks, storage in basins or 


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pits, loading and unloading activities, pipeline transport (above and underground), pumping, 

handling opened barrels, handling of bulk materials, storage and transfer of packed liquids and 

solids (drums, bins, cans, etc.), enclosed or (half) open processing plants, sewage systems, 

emergency containment facilities, workshop activities and waste water treatment. All of these 

activities are likely to occur on shale gas drilling and production sites. 

3. How to reach a negligible soil risk 

As described above, negligible soil risk can be reached in different ways: Do you want to opt for 

robust soil protection provisions with low operational impact (left side of the Figure 4-39), or do 

you settle for less robust facilities, accepting a bigger impact on operations (more input from 

operating staff; the right side of the Figure 4-39). 

4.4.4.2.3 Conclusion 

The Dutch Soil Protection Guideline is relevant and applicable to activities on shale gas drilling and 

production sites as it is done with respect to drilling and production sites for conventional gas. A typical 

production site in The Netherlands is presented in the picture below. 

Figure 4-40. A typical production site in the Netherlands 

4.4.4.3 HSE Management – Summary 

As with the General Environmental discussions above, for the purposes of the notional and or feasibility 

study, it is important to understand that any shale gas development program in the Netherlands must 

take into account the Dutch regulations with regards to External Safety (risk management) and Soil 

Protection. At this point in the process, there are too many unknowns to determine the extent of the 

activities and operations that would be implemented, but an awareness of these provisions is essential 

in any planning going forward. 


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4.5 Well Pad Construction 

As a part of this feasibility study, the Team has been involved in an iterative process of designing the 

most favorable locations for well pad sites 

4.5.1 Go – No-Go Areas 

We developed an initial Geographic Information System (GIS) database divided the conceptual study 

area into three (3) categories: 

1. NO GO areas, which are: 

o Buildings 

o Surface waters 

o Roads 

o Railways 

o Overhead power lines 

o Existing safety zones 

o Archeological monuments 

o Drinking water production areas 

2. MIGHT GO areas, which are 

o Ecological sensitive areas (Main Ecological Structure (EHS)) 

o Natura2000 areas 

o Ground water protection areas 

o Drill free zone drinking water 

3. GO areas: which are open, agricultural areas 

For the GIS evaluation, the pad size has been assumed to be 150 x 150 m, which roughly leaves a ‘buffer 

zone’ of about 75m around the well pad. Using the midpoint co-ordinates of the well pads, it has been 

evaluated whether or not an intersection of the well pad area with either a no-go, or a might go 

intersection exists: 

· If no intersection with NO-GO and MIGHT GO exists, the location of the well pad is considered 

feasible 

· If intersections with a NO-GO area exist, the location of the well pad is considered NOT to be 

feasible 

· If intersections with a MIGHT GO area exist, additional evaluation of the suitability might be an 

option, but for the time being, the location of the well pad was considered NOT to be feasible. 

Based on the above, 83 well pad locations – within the 8C area - that seemed to be suitable for 

development were identified. The Figure on the next page shows the location of these possible well pad 

sites and the five hectare section of land for our “Base Case” site. 


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Due to the requirement to store water on location during drilling and fracking operations, there is a 

need to construct large impoundments (reservoirs, ponds, pits) in nearby locations where the water is 

readily accessible, so as to not impede the processes. 

The typical well site might have two separate impoundments constructed for the storage of water for 

distinct purposes. One impoundment is specifically designated for the storage of flowback and 

produced water, and a second impoundment is designated for the storage of fresh water for use during 

drilling and fracking operations. 

4.5.2 Well Pad Designs 

The actual design of the surface “footprint” involves a number of engineering (geotechnical and civil) 

and compliance related aspects. In order to minimize the size of the actual well pad and the overall 

footprint of a shale gas development plan, a common practice is to drill multiple horizontal wells from 

the same well pad. One of the Assumptions noted in Section 6.0 – Project Description, notes that the 

proposed development plan would look at drilling up to ten (10) wells from each well pad. Using the 

“Base Case” site as defined in Section 6.0 that could result in 130 wells within the area. 

By drilling multiple horizontal wells from the same well pad, the Operator is able to reduce their site 

footprint that results in a number of other benefits: 

• Lower construction costs 

• Less surface disturbance 

• Less habitat fragmentation 

• Fewer roads and utility corridors 


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Figure 4-41. Wellheads on multi-well pad site 

4.5.3 Seismic Activity 

The surface facilities (well pads, processing facilities, pipelines, office structures, etc.) must be designed 

to withstand the remote possibility of earthquakes and tremors in the development area. If this 

information is not already available, a detailed geotechnical seismology evaluation should be performed. 

Some of the items this study should address would include: 

• Site geology and soil conditions 

o Liquefied sands 

o Quick sensitive sands 

o Thick deposits of soft soils overlying rock 

• Seismic design parameters 

o PGA (Peak Ground Acceleration) 

o PGV (Peak Ground Velocity 

o PGD (Peak Ground Displacement) 

• Possibility for permanent displacement (could impact pipelines) 


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Figure 4-42. Representation of 3D seismic data 

4.5.4 Geotechnical Engineering 

In addition to looking at seismic potential, a thorough geotechnical investigation (with soil borings) 

should be performed to facilitate the proper design of all surface facilities. Civil engineers would then 

be able to utilize this geotechnical data and other sources of information to design the well pads and 

associated surface facilities for the field activities and on-site equipment required for shale gas 

development. Included in their designs would be various compliance plans such as an Erosion and 

Sediment Control Plan. 


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Figure 4-43. Geotechnical soil boring 

The Figure 4-44 shows a typical well pad design prepared for a site in the Marcellus. 


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Figure 4-44. Typical Well Pad Design 


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4.5.5 Impoundments 

In addition to the well pads, there are a number of associated surface related facilities which would 

include in the site development plan. 

As water is required to be stored on location during the drilling and fracing operations, there is a need to 

construct large impoundments (reservoirs, ponds, pits) in near-by locations where the water is readily 

accessible so as to not impede the processes. 

Figure 4-45. Wellpad with impoundment 

The typical well site has two separate impoundments constructed for the storage of water for distinct 

purposes. One impoundment is specifically designated for the storage of flowback and produced water 

and a second impoundment is designated for the storage of fresh water for use during the drilling and 

fracing operations. 


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Figure 4-46. Impoundment for storage of water 

This siting of these impoundments should be planned in conjunction with the drilling plan / schedule 

such that they are located in a centralized area so that water can be transferred to the various well 

pads. The water is transferred via pipelines from the source water receiving point (surface water, grey 

water provider) to these impoundments and then from the impoundment to the well pad. These 

pipelines are typically HDPE or PVC and can above ground or buried. In some instances when the 

topography necessitates, pumps may be required to obtain the necessary lift for the water or due to the 

distance between the centralized impoundment and the well pad. 

Figure 4-47. Installation of liner system for impoundment 


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These impoundments must be designed by licensed engineers and comply with the regulatory 

authorities permitting requirements. Typical components of an impoundment design include: 

• Information on site geology and soil conditions 

• Criteria for a preparation of sub-base and compaction 

• Double lined with a runway 

o Some designs include the use of a geotextile barrier to protect / cushion the liner and 

help remove naturally occurring methane from being trapped under the liner 

• Under-drain catch basin with a leak detection system 

• Minimum of 30-mils (HDPE or PVC) 

• Permanent fill / withdrawal manifold 

• Front-end weir tank battery for solids and condensate capture 

• Possible aeration system to reduce bacteria build-up 

• Bird netting (if required) 

• Remote level monitoring system (solar powered) 

• Security / privacy fencing 

• Specifications for installer’s qualifications and work practices 

• Construction inspection / certification requirements 

The Figure 4-48 shows a typical impoundment design. 


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Figure 4-48. Typical Impoundment Design 


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An important benefit of centralized impoundments and pipelines is the reduced truck traffic associated 

with the hauling of water for the drilling and fracking operations. This design reduces the roadway 

congestion, damage to the roadways due to heavy vehicles and reduced air emissions and GHG 

(greenhouse gas) concerns. 

Figure 4-49. Impoundment with above-ground water pipelines along side of roadway 

4.5.6 Restoration 

Shale gas producers aim to leave behind a small footprint for each well pad through the restoration 

process. Restoration involves landscaping and contouring the property as closely as possible to predrilling 

conditions. The production site will include a small wellhead on a level concrete pad, a small 

amount of equipment, two to three water storage tanks and a metering system to monitor gas 

production. 

A site specific restoration plan will be developed that will take into account the visual impacts, the 

roadways, storm water and erosion & sediment control management and security for the site. 

Components of a restoration plan would include: 

• Original use of property 

• Soils evaluation 

• Natural vegetation 

• Wildlife habitat 

• Erosion control measures 

• Impacts on nearby water bodies 

• Timeline of restoration 


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• Maintenance plan 

• Monitoring of restoration progress 

Figure 4-50. Stored wellpad site with wellheads and produced water storage tanks 


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4.6 Infrastructure 

The characterization of the shale gas resources in geologic formations beneath the earth surface is a 

critical component to the economic viability of a shale gas development effort. However, it is equally 

important to evaluate the surface conditions and identify the potential surface impacts and determine 

the infrastructure that would be required to support the subsurface development plans. The 

investments required to build-out the infrastructure can be significant and the permitting and regulatory 

approval process can have a material impact upon the project’s schedule and budget. 

One of the unique aspects of the infrastructure build-out is that is on the surface and can be readily 

observed by the community surrounding the proposed development area. This infrastructure also has 

the potential to impact their quality of life. 

It has been said that the science, engineering and technology to identify and harness these shale gas 

resources is the easy part; it is when the production and the shipment of the gas starts to affect the 

surrounding communities - which is when the real challenges begin. 

Some gas plays are in remote, sparsely populated areas while others are located in urban areas that are 

more densely populated. Each scenario presents its own challenges. 

While operating in a remote area, the infrastructure required to support the development effort has to 

be built-out and the distances to get the product to market can result in increased project costs. The 

build-out of roadways, pipeline right-of-ways and processing facilities will result in the landscape being 

changed. 

While operating in a more urban area and closer to existing infrastructure may result in reduced buildout 

costs, the activities required to perform and complete the shale gas extraction may have an impact 

upon the population. 

The infrastructure required to support the development of the shale gas resources would include things 

such as: 

• Roadways 

• Utilities 

• Gathering systems 

• Processing facilities 

• Pipelines 

4.6.1 Roadways 

The equipment used to drill for these resources and the facilities required to process and transport the 

shale gas all have to be mobilized to the site or built on-location. Depending upon where a particular 

shale gas resource is located, the types and condition of the roadways can vary significantly. 


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Figure 4-51. Typical drilling rig 

The list of equipment required to develop shale gas resources is extensive and all of it has some 

common attributes; it is large and heavy. The movement of the equipment to and from a project site 

can present some unique challenges. The existing roadways are typically designed for passenger 

vehicles and commercial transportation and often have weight and height restrictions. This leads to the 

development of detailed transportation plans for special permits, route selection and scheduling 

requirements. 

A typical exploration and production operation is usually a 24 hour per day / 7 days a week (24/7) 

operation. If the movement of the equipment and supplies may result in increased congestion within 

high traffic areas, limits may be placed upon how many vehicles and timing of their movements will be 

allowed. 


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Figure 4-52. Staging of equipment for fracing operation 

As noted above, many of the existing roadways were not designed for this type of large, heavy 

equipment and the sheer number of vehicles required. Many Operators end up having to contract with 

local road construction companies to repair and maintain these roadways and in some instances, build 

new roads. The resultant investment in roadway infrastructure can be significant. 

In addition to the public roadways, it is typical for Operators to include the construction of on-site access 

roads into their site development plans. Some of these roads are temporary (dirt / gravel) and others 

are permanent (pavement). All of these roads and associated work areas have to be designed and 

constructed with the regards to the site terrain, bad weather conditions and take into account the 

requirement for proper consideration for soil and erosion control measures. It is also necessary to 

ensure all of the appropriate ecological field studies have been performed prior to beginning any site 

activities to determine if there is the potential to impact wetland areas or protected species. As noted 

above, these issues are regulated under a number of different Dutch statutes. 


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Figure 4-53. Asphalt road constructed to access produced water tanks 

4.6.2 Utilities 

During the exploration phase of a project, much of the equipment is powered by portable generators. 

Due to horsepower requirements to operate this equipment, these portable generators are large, 

require their own fuelling systems, emit air emissions into the atmosphere and can create noise issues. 

As noted in the sections above, these concerns need to be factored into any shale gas development 

plan. 

Once the well is completed and moves into a production phase there are a different set of power 

requirements that must be considered. The processing equipment and other facilities are more 

permanent in nature are many times are powered by the local power grid. The voltage requirements of 

the entire complex must be assessed to determine if the facility will require some type of on-site 

substation. In addition, the distance of the location from the power grid may require the construction of 

additional transmission lines resulting in additional linear surface impacts and a significant investment 

costs. 


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Figure 4-54. Electrical substation 

The investment in transmission & distribution (T&D) infrastructure can be substantial and may involve a 

lengthy permitting process which would need to be factored into the development plan schedule. 

4.6.3 Gathering Systems 

Once a well is completed and the wellhead is in-place, there has to be a means of gathering the gas from 

the individual wells and transporting it to a processing facility. These gathering lines are typically 6 to 12 

inch diameter steel pipelines that are buried across the development area and routed to the gas 

processing facility. Depending upon the wellhead pressure, there may be a need for some level of 

compression to move the gas. 

Figure 4-55. Gas gathering system 


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As a development area is built-out, the network of gathering lines can become extensive and it is 

important to plan for future field development in relation to route selection and proper sizing of these 

gathering pipelines. 

As discussed on the section on roadways, there is a requirement to perform the appropriate preconstruction 

field studies to determine if the linear route of these pipelines will have any type of 

environmental impacts upon areas such as wetlands, stream or river crossings, threatened & 

endangered species, archaeological sites and flora and fauna / biological media. These field studies and 

the associated permitting process and timelines can have an impact upon a project from cost and 

scheduling perspective. In many instances, mitigation plans with offset requirements will need to be 

developed and implemented. 

4.6.4 Processing Facilities 

Gas processing facilities are designed to remove impurities from the gas stream to bring it up to 

“pipeline spec” so that it can be sold into the marketplace. Because the geochemical composition of the 

host formation for the shale gas varies, the list of “impurities” that need to be removed will also vary 

depending upon the source of shale gas and each processing facility needs to be designed to treat the 

relevant constituents. These units are designed to remove water, CO 2, H 2 S, and fractionate (separate) 

liquid and vapor products to meet pipeline specifications. 

Figure 4-56. Typical gas processing facility 


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Although the specific design criteria for the processing facility will be dependent upon the analysis of 

site specific gas samples, some of the typical processes would include: 

• Amine processing – this process is used to remove carbon dioxide (CO 2 ) and hydrogen sulfide 

(H 2 S) which are referred to as acid gas compounds and the acid gas removal process is often 

referred to gas sweetening. This is a continuous process where the acid gas compounds are 

selectively absorbed from the gas stream under conditions of high pressure and moderate 

temperature. Conditions in the regenerator area of high temperature and low pressure cause 

the acid gas compounds to desorb from the amine solution and the cooled solution is returned 

to the high pressure absorber for the removal of additional acid gas compounds. 

• Refrigeration / Dew point Control – many gas streams contain excessive amounts of liquefiable 

hydrocarbons. To prevent condensation of these during pipeline transport, the gas stream is 

dehydrated and cooled below any expected pipeline condition. Liquid product produced is 

stabilized for the required duty and the gas is warmed for transportation. 

• Condensate stabilization – many natural gas steams produce a light hydrocarbon liquid product 

which is referred to as condensate. In order for this liquid to be shipped safely at atmospheric 

pressure and avoid high vaporization losses, the liquid must be stabilized using heat and a 

fraction tower to set the liquid vapor pressure within acceptable limits. The light products 

removed from the heavier liquid can be used as a fuel and many other uses. The stabilized 

liquid is then cooled and put into storage tanks. 

• Glycol Dehydration – water vapor must be removed from natural gas to prevent pipeline 

corrosion and mechanical damage to downstream equipment. The most common method for 

this procedure involves the use of TriEthylene Glycol (TEG) in a continuous process in which 

water vapor is absorbed from the gas under conditions of high pressure and moderate 

temperature. Regenerator conditions of low pressure and high temperature cause the water to 

be released from the TEG and the cooled TEG is returned to the TEG absorber for additional 

removal of water vapor. 

• BTEX Removal – some gas streams contain BTEX (Benzene, Toluene, Ethylbenezene and Xylene) 

components and aromatics from amine plant vent streams are removed. 

As noted above, each processing facility is designed to meet the requirements of a specific gas stream 

but the diagram below shows the components of a typical gas processing facility. 


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Figure 4-57. Gas processing facility 

These gas processing facilities are engineered to handle a specific chemical composition and throughput 

(volume) of gas and many times are designed as packaged skid-mounted units. These facilities are 

scalable to meet increased production volumes. 

4.6.5 Metering Station 

Once the gas has been cleaned-up and brought up to “pipeline spec”, it is ready to be shipped to 

market. An important piece of equipment is the metering station which monitors the performance of 

the pipeline and measures the volumes of gas through-put being transferred to the pipeline grid. This 

metering station is sometimes referred to as the “city gate” because the gas is measured and tested as it 

leaves the processing plant and enters the mainline pipeline. The information is typically shared (and 

verified) by all parties in the transaction – the Operator / midstream processor and the pipeline 

(shipper) company. 

Although commonly referred to as the metering station, the station actually consists of a series of filters, 

valves, gauges, instrumentation, regulators, heaters, tanks and piping spools. 


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Figure 4-58. Metering station 

One important function that can be performed at the metering station is the activation of the shut-off 

valve in the case of operational issues or safety concerns. These metering stations are linked into a 

SCADA (supervisory control and data acquisition) system which consists of a series of instrumentation 

that transmits data into a computer system to monitor and control the facility. The station can be 

monitored by on-site personnel or remotely from a centralized control room at an off-site location. 

4.6.6 Produced Water Tanks 

One of the bi-products / waste generated within a processing facility is produced water. Within the 

midstream sector this is a broad term that includes actual formation water that is absorbed into the gas 

molecules, condensates and other residuals that are processed out of the gas stream. This produced 

water is routed over to tanks for storage and eventual disposal. These produced water tanks are also 

commonly referred to as “slop water” tanks because of the variety of liquid waste streams that are 

often deposited into them. Depending upon the waste / water volumes anticipated, there are typically 

several (1 – 4) tanks linked together and referred to as a tank battery. The tanks are made of steel or 

fiberglass and can range in size but a typical volume would be 400 to 500 gallons (each tank). The tank 

battery is built with a secondary containment system to control spillage and a series of valves to 

facilitate their draw-down for disposal. 


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The facility would contract with a waste hauler to transport this water / waste to an off-site approved 

disposal site (treatment plant or disposal well). The volumes of water collected would determine the 

frequency with which the waste hauler would schedule a pick-up at the site. 

Figure 4-59. Produced water tanks with secondary containment 

4.6.7 Gas Pipelines (Mainlines) 

Mainline transmission pipelines are the means by which the gas is shipped from the processing facility to 

their markets. The pipelines are usually between 16 and 48 inches in diameter and made from a strong 

carbon steel material, engineered to meet industry standards. These pipes are coated with a fusion 

bond epoxy to protect the pipe from moisture, which causes corrosion and rusting. In addition, cathodic 

protection is installed as a secondary method of protecting against corrosion and rusting. 

4.6.7.1 Compressor Stations 

The gas is shipped through the pipeline at high pressures. To ensure gas remains pressurized, 

compression of the gas along the pipeline is required and compressor stations are constructed at 

intervals usually between 40 and 100 miles. There are different types of compressors used to compress 

the gas. 


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Figure 4-60. Skid-mounted compressor 

Turbine compressors gain their energy by using up a small proportion of the natural gas that they 

compress. The turbine operates a centrifugal compressor, which contains a type of fan that compresses 

and pumps the natural gas through the pipeline. 

Some compressor stations are operated by using an electric motor to turn the same type of centrifugal 

compressor. This type of compression does not require the use of any of the natural gas from the 

pipeline however it does require a reliable source of electricity nearby. 

Reciprocating natural gas engines are also used to power some compressor stations. These engines 

resemble a very large automobile engine, and are powered by natural gas from the pipeline. The 

combustion of the natural gas powers pistons on the outside of the engine, which serves to compress 

the natural gas. 

In addition to compressing natural gas, compressor stations also usually contain some type of liquid 

separator, much like the ones used to dehydrate natural gas during its processing. Usually, these 

separators consist of scrubbers and filters that capture any liquids or other unwanted particles from the 

natural gas in the pipeline. Although natural gas in pipelines is considered 'dry' gas, it is not uncommon 

for a certain amount of water and hydrocarbons to condense out of the gas stream while in transit. 

These liquid separators at compressor stations ensure that the natural gas in the pipeline is as pure as 

possible, and usually filter the gas prior to compression. 


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4.6.7.2 Metering Stations 

In addition to compressing natural gas to reduce its volume and push it through the pipe, metering 

stations are placed periodically along the pipelines. These stations allow pipeline companies to monitor 

the natural gas in their pipes. Essentially, these metering stations measure the flow rates, pressure and 

temperature of the gas along the pipeline, and allow pipeline companies to 'track' the gas all along the 

pipeline. These metering stations employ specialized meters to measure the natural gas as it flows 

through the pipeline, without impeding its movement. 

Figure 4-61. Metering station along transmission pipeline 

4.6.7.3 Valves 

The pipelines have a number of large block valves located along their route. These valves are 

strategically positioned every 5 to 20 miles along the pipeline and can be closed off to facilitate 

maintenance activities and in the event of an emergency. 

4.6.7.4 Control Systems 

In order to manage the natural gas that enters the pipeline, and to ensure timely delivery of the gas, 

sophisticated control systems are required to monitor the gas as it travels through all sections of what 

could be a very lengthy pipeline network. The same SCADA system that monitors the gas coming out of 

the metering station located at the processing facility is used to monitor and control the flow of the gas 

the entire length of the pipeline. 


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Figure 4-62. Control room for monitoring of SCADA system 

Pipeline engineers are located in centralized gas control centers to collect, assimilate, and manage data 

received from monitoring and compressor stations all along the pipe. Flow rates, operational status, 

pressure, and temperature readings may all be used to assess the status of the pipeline in real time. 

This process allows the pipeline engineers to know exactly what is happening along the pipeline at all 

times and enables quick reactions to equipment malfunctions, leaks, or any other unusual activity along 

the pipeline. These SCADA systems facilitate remote operation of equipment along the pipeline, 

including compressor stations, allowing the engineers to immediately and easily adjust flow rates in the 

pipeline. 

4.6.7.5 Pipeline Construction 

Constructing natural gas pipelines requires a great deal of planning and preparation. In addition to 

actually building the pipeline, several permitting and regulatory processes must be completed. Prior to 

beginning the permitting and land access processes, natural gas pipeline companies prepare a feasibility 

analysis to ensure that an acceptable route for the pipeline exists that provides the least possible impact 

to the environment and public infrastructure already in place. 


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Figure 4-63. Pipeline right-of-way during construction 

Assuming a pipeline company obtains all the required permits and satisfies all of the regulatory 

requirements, construction of the pipe may begin. Extensive surveying of the intended route is 

completed, both aerial and land based, during the actual assembly of the pipeline. 


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Figure 4-64. Surveying the right-of-way 

Installing a pipeline is much like an assembly line process, with sections of the pipeline being completed 

in stages. First, the path of the pipeline is cleared of all removable impediments, including trees, 

boulders, brush, and anything else that may prohibit the construction. Once the pipeline's path has 

been cleared sufficiently to allow construction equipment to gain access, sections of pipes are laid out 

along the intended path, a process called 'stringing' the pipe. These pipe sections are commonly from 

40 to 80 feet long, and are specific to their destination. 

Once the pipe is in place, trenches are dug alongside the laid out pipe. These trenches are typically five 

to six feet deep, as the regulations require the pipe to be at least 30 inches below the surface. In certain 

areas, however, including road crossings and bodies of water, the pipe is buried even deeper. Once the 

trenches are dug, the pipe is assembled and contoured. This includes welding the sections of pipe 

together into one continuous pipeline, and bending it slightly, if needed, to fit the contour of the 

pipeline’s path. Coating is applied to the ends of the pipes. The coating applied at a coating mill 

typically leaves the ends of the pipe clean, so as not to interfere with welding. Finally, the entire coating 

of the pipe is inspected to ensure that it is free from defects. 

Once the pipe is welded, bent, coated, and inspected it can be lowered into the previously dug trenches. 

This is done with specialized construction equipment acting to lift the pipe in a level manner and lower it 

into the trench. Once lowered into the ground, the trench is filled in carefully, to ensure that the pipe 

and its coating retain their integrity. 


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Figure 4-65. Lowering of pipe into trench 

Laying pipe across streams or rivers can be accomplished in one of two ways. Open cut crossing involves 

the digging of trenches on the floor of the river to house the pipe. When this is done, the pipe itself is 

fitted with a concrete casing, which both ensures that the pipe stays on the bottom of the river and adds 

an extra protective coating to prevent any natural gas leaks into the water. 

Alternatively, a form of directional drilling may be employed, in which a 'tunnel' is drilled under the river 

through which the pipe may be passed. The technique referred to as horizontal directional drilling 

(HDD) can also be used to tunnel underneath a roadway. 


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Figure 4-66. Equipment for boring on horizontal directional drilling (HDD) operations 

Essentially, installing utility tunnels using the HDD technique comprises the following three stages: 

• In the first stage a pilot bore is made from the point of attack in the direction of the exit point. 

The steerable drill string made up of individual drill rods is conducted along the target route by a 

guidance system located directly behind the cutterhead. 

• During the drilling process a bentonite suspension is pumped to the nozzles fitted to the 

cutterhead where it excavates the native soil hydraulically. The bentonite mixes with the 

excavated soil and flows back through the annulus between the drill rods and the bore hole to 

the point of attack at the surface, where it is processed by a separation plant and returned to 

the drilling cycle. 

• In order to increase the diameter of the pilot bore hole in the second stage, the pilot cutterhead 

is removed at the exit point and a so-called muck bucket lips is attached to the drill rod. As the 

drill string is retracted, the diameter of the bore hole is enlarged with the help of the muck 

bucket lips. All the muck bucket lips are fitted with nozzles and excavation tools in order to 

excavate the soil both hydraulically and mechanically. A mixture of water and bentonite or other 

additives can be used dependent on soil conditions in order to stabilize the bore hole and 

reduce friction forces. In the third stage the prefabricated and pipelines that have been checked 

are retracted. 


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• The front part of the pipeline laid out in front of the bore hole is lifted to line up with the exit 

angle of the bore hole in order to keep outside the minimum bend radius. The pipeline is 

retracted section by section from the rig behind a muck bucket lips and in this way reaches its 

final position in the soil. 

HDD technology can be used in this way in geological conditions ranging from soft to very hard 

formations. 

4.6.8 Hydrostatic Testing 

Before the pipeline is put into service, the entire length of the pipeline is pressure tested using water. 

The hydrostatic test is the final construction quality assurance test. There are very detailed 

requirements for this test and the pipeline may be divided into sections depending on the varying 

elevation of the terrain along the route and the availability of water used in the testing. 

Each section is filled with water and pressured up to a level higher than the maximum operating 

pressure. The test pressure is held for a specific period of time to determine if it meets the design 

strength requirements and if any leaks are present. Once a test section successfully passes the 

hydrostatic test, water is emptied from the pipeline and disposed of in accordance with regulatory 

requirements. The pipeline is then dried to assure it has no water in it before gas is put into the 

pipeline. 

4.6.9 Site Restoration 

Once the pipeline has been installed and covered, extensive efforts are taken to restore the pipeline's 

pathway to its original state, or to mitigate any environmental or other impacts that may have occurred 

during the construction process. These steps often include replacing topsoil, fences, irrigation canals, 

and anything else that may have been removed or upset during the construction process. 


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Figure 4-67. Restoration of pipeline right-of-way 

The restoration crew carefully grades the right-of-way. In hilly areas, the crew installs erosion 

prevention measures such as interceptor dikes, which are small earthen mounds constructed across the 

right-of-way to divert water. 

The restoration crew also installs riprap, consisting of stones or timbers, along streams and wetlands to 

stabilize soils. As a final measure, the crew may plant seed and mulch the construction right-of-way, to 

ensure the foliage and grassland is restored as close as possible to its original condition. The pipeline 

operator maintains an obligation to maintain the right-of-way in as long as the pipeline is in-service. 

4.6.10 Pipeline Inspection 

In order to ensure the efficient and safe operation of the extensive network of natural gas pipelines, 

pipeline companies routinely inspect their pipelines for corrosion and defects. This is done through the 

use of sophisticated pieces of equipment known as ‘smart pigs.’ Smart pigs are intelligent robotic 

devices that are propelled down pipelines to evaluate the interior of the pipe. Smart pigs can test pipe 

thickness, and roundness, check for signs of corrosion, detect minute leaks, and any other defect along 

the interior of the pipeline that may either impede the flow of gas, or pose a potential safety risk to the 

operation of the pipeline. Sending a smart pig down a pipeline is fittingly known as 'pigging' the 

pipeline. 


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Figure 4-68. Pigging inspection tool 

Pipelines are designed with spools of pipe that are referred to as “pig launchers” which are located 

along the pipeline to facilitate the testing and cleaning of the pipeline with pigs. 

Figure 4-69. Pig launchers 

4.6.11 Pipeline Safety 

Pipeline safety is a critical component of operating a pipeline. In addition to monitoring the pipelines for 

corrosion, companies are on constant alert to damage to their pipelines caused by others. Unauthorized 

construction and digging are the primary causes of damage to pipelines. Pipeline operators employ a 

number of safety precautions along their route: 

• Aerial Patrols - Planes are used to ensure no construction activities are taking place too close to 

the route of the pipeline, particularly in residential areas. 

• Leak Detection - Natural gas detecting equipment is periodically used by pipeline personnel on 

the surface to check for leaks. This is especially important in areas where the natural gas is not 

odorized. 


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• Pipeline Markers - Signs on the surface above natural gas pipelines indicate the presence of 

underground pipelines to the public, to reduce the chance of any interference with the pipeline. 

• Gas Sampling - Routine sampling of the natural gas in pipelines ensures its quality, and may also 

indicate corrosion of the interior of the pipeline, or the influx of contaminants. 

• Preventative Maintenance - This involves the testing of valves and the removal of surface 

impediments to pipeline inspection. 

• Emergency Response - Pipeline companies have extensive emergency response teams that train 

for the possibility of a wide range of potential accidents and emergencies. 

• The One Call Program – The pipeline industry has instituted what is known as a 'one call' 

program, which provides excavators, construction crews, and anyone interested in digging into 

the ground around a pipeline with a single phone number that may be called when any 

excavation activity is planned. This call alerts the pipeline company, which may flag the area, or 

even send representatives to monitor the digging. 

Figure 4-70. Markers along pipeline right-of-way 

4.7 Waste Management 

The management of wastes associated with drilling and production of shale gas is an important element 

in any development program. Industry associations, regulatory agencies and Operators have worked 

collaboratively to develop guidelines for waste management plans which include waste minimization as 

an integral part of the plan. The steps recommended for development of plan include: 

• Company management approval and commitment 

• Identification of area for which plan is developed 


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• Regulatory analysis 

• Waste identification 

• Waste classification 

• Waste disposal options 

• Waste minimization 

• Selection of preferred waste management practices 

• Creation of a formal written plan 

• Periodic review and update of plan 

The identification and refinement of best management practices (BMPs) for the management of wastes 

has been a long-term focus of the oil & gas industry. 

4.7.1 Waste Streams 

The two primary waste streams of gas development are water and drilling fluids. 

4.7.2 Fracing Fluids 

The hydraulic fracture process itself requires millions of gallons of water-based fracturing fluids mixed 

with proppant materials are pumped in a controlled and monitored manner into the target shale 

formation above fracture pressure. 

The fracturing fluids used for gas shale stimulations consist primarily of water but also include a variety 

of additives. The number of chemical additives used in a typical fracture treatment varies depending on 

the conditions of the specific well that is being fractured. A typical fracture treatment will use very low 

concentrations of between 3 and 12 additive chemicals depending on the characteristics of the water 

and the shale formation being fractured. Each component serves a specific, engineered purpose. The 

predominant fluids currently being used for fracture treatments in the gas shale plays are water-based 

fracturing fluids mixed with friction‐reducing additives and the process is referred to as a “slickwater 

frac”. 

The addition of friction reducers allows fracturing fluids and proppant to be pumped to the target zone 

at a higher rate and reduced pressure than if water alone were used. In addition to friction reducers, 

other additives include: biocides to prevent microorganism growth and to reduce bio fouling of the 

fractures; oxygen scavengers and other stabilizers to prevent corrosion of metal pipes; and acids that 

are used to remove drilling mud damage within the near wellbore area. These fluids are used not only 

to create the fractures in the formation but also to carry a propping agent (typically silica sand) which is 

deposited in the induced fractures. 

The make‐up of fracturing fluid varies from one geologic basin or formation to another. Evaluating the 

relative volumes of the components of a fracturing fluid reveals the relatively small volume of additives 


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that are present. The additives depicted on the right side of the pie chart represent less than 0.5% of 

the total fluid volume. Overall the concentration of additives in most slickwater fracturing fluids is a 

relatively consistent 0.5% to 2% with water making up 98% to 99.5%. 

Figure 4-71. Graph of fracing fluid composition 

Because the make-up of each fracturing fluid varies to meet the specific needs of each area, there is no 

one-size-fits-all formula for the volumes for each additive. In classifying fracturing fluids and their 

additives, it is important to realize that service companies that provide these additives have developed a 

number of compounds with similar functional properties to be used for the same purpose in different 

well environments. The difference between additive formulations may be as small as a change in 

concentration of a specific compound. Although the hydraulic fracturing industry may have a number of 

compounds that can be used in a hydraulic fracturing fluid, any single fracturing job would only use a 

few of the available additives. It is not uncommon for some fracturing recipes to omit some compound 

categories if their properties are not required for the specific application. 

Most industrial processes use chemicals and almost any chemical can be hazardous in large enough 

quantities or if not handled properly. Even chemicals that go into our food or drinking water can be 

hazardous. For example, drinking water treatment plants use large quantities of chlorine. 

When used and handled properly, it is safe for workers and near‐by residents and provides clean, safe 

drinking water for the community. Although the risk is low, the potential exists for unplanned releases 

that could have effects on human health and the environment. By the same token, hydraulic fracturing 

uses a number of chemical additives that could be hazardous, but are safe when properly handled 

according to requirements and long‐standing industry practices. In addition, many of these additives are 

common chemicals which people regularly encounter in everyday life. 


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Table 4-13. Fracturing Fluid Additives, Main Compounds, and Common Uses 

Additive Type Main Compound Purpose Common Use of Main 

Compound 

Diluted Acid (15%) Hydrochloric acid or 

muriatic acid 

Help dissolve minerals and 

initiate cracks in the rock 

Swimming pool chemical 

and cleaner 

Biocide Glutaraldehyde Eliminates bacteria in the 

water that produce 

corrosive byproducts 

Breaker Ammonium persulfate Allows a delayed break 

down of the gel polymer 

chains 

Corrosion Inhibitor N,n‐dimethyl formamide Prevents the corrosion of 

the pipe 

Crosslinker Borate salts Maintains fluid viscosity as 

temperature increases 

Friction Reducer Polyacrylamide Minimizes friction 

between the fluid and the 

pipe 

Gel 

Guar gum or hydroxyethyl Thickens the water in 

cellulose 

order to suspend the sand 

Iron Control Citric acid Prevents precipitation of 

metal oxides 

KCl Potassium chloride Creates a brine carrier 

fluid 

Oxygen Scavenger Ammonium bisulfite Removes oxygen from the 

water to protect the pipe 

from corrosion 

pH Adjusting Agent Sodium or potassium Maintains the 

carbonate 

effectiveness of other 

components, such as 

crosslinkers 

Proppant Silica, quartz sand Allows the fractures to 

remain open so the gas 

can escape 

Scale Inhibitor Ethylene glycol Prevents scale deposits in 

the pipe 

Surfactant Isopropanol Used to increase the 

viscosity of the fracture 

fluid 

Disinfectant; sterilize 

medical and dental 

equipment 

Bleaching agent in 

detergent and hair 

cosmetics, manufacture of 

household plastics 

Used in pharmaceuticals, 

acrylic fibers, plastics 

Laundry detergents, hand 

soaps, and cosmetics 

Water treatment, soil 

conditioner 

Cosmetics, toothpaste, 

sauces, baked goods, ice 

cream 

Food additive, flavoring in 

food and beverages; 

Lemon Juice ~7% Citric 

Acid 

Low sodium table salt 

substitute 

Cosmetics, food and 

beverage processing, 

water treatment 

Washing soda, detergents, 

soap, water softener, glass 

and ceramics 

Drinking water filtration, 

play sand, concrete, brick 

mortar 

Automotive antifreeze, 

household cleansers, and 

de‐ icing agent 

Glass cleaner, 

antiperspirant, and hair 

color 

Note: The specific compounds used in a given fracturing operation will vary depending on company preference, source water 

quality and site‐specific characteristics of the target formation. The compounds shown above are representative of the major 

compounds used in hydraulic fracturing of gas shales. 


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The Table above provides a summary of the additives, their main compounds, the reason the additive is 

used in a hydraulic fracturing fluid, and some of the other common uses for these compounds. 

Hydrochloric acid (HCl) is the single largest liquid component used in a fracturing fluid aside from water; 

while the concentration of the acid may vary, a 15% HCl mix is a typical concentration. A 15% HCl mix is 

composed of 85% water and 15% acid, therefore, the volume of acid is diluted by 85% with water in its 

stock solution before it is pumped into the formation during a fracturing treatment. Once the entire 

stage of fracturing fluid has been injected, the total volume of acid in a typical fracturing fluid for shale 

frac would be 0.123%, which indicates the fluid had been diluted by a factor of 122 times before it is 

pumped into the formation. The concentration of this acid will only continue to be diluted as it is 

further dispersed in additional volumes of formation water that may be present in the subsurface. 

Furthermore, if this acid comes into contact with carbonate minerals in the subsurface, it would be 

neutralized by chemical reaction with the carbonate minerals producing water and carbon dioxide as a 

byproduct of the reaction. 

4.7.3 Flowback Water 

After a hydraulic fracture treatment, when the pumping pressure has been relieved from the well, the 

water‐based fracturing fluid, mixed with any natural formation water present, begins to flow back 

through the well casing to the wellhead. This flowback water may also contain dissolved constituents 

from the formation itself. The dissolved constituents are naturally occurring compounds and may vary 

from one shale play to the next or even by area within a shale play. Initial produced water can vary from 

fresh (


Figure 4-72. Samples of flowback and produced water 

4.7.4 Produced Water 

It is estimated that 97% + of the oil & gas waste generated (by volume) is produced water. After initial 

gas production begins to flow to the wellhead, the formation water is brought to the surface with the 

gas and is referred to as produced water. 

This natural formation water has been in contact with the reservoir formation for millions of years and 

contains minerals native to the reservoir rock. The salinity, TDS, and overall quality of formation water 

vary by geologic basin and specific rock strata. Produced water can vary from brackish (5,000 ppm to 

35,000 ppm TDS), to saline (35,000 ppm to 50,000 ppm TDS), to supersaturated brine (50,000 ppm to 

>200,000 ppm TDS) and some operators report TDS values greater than 400,000 ppm. The variation in 

composition changes primarily with changes in the natural formation water chemistry. 

Treatment of produced water may be feasible through either self‐contained systems at well sites or 

commercial treatment facilities. Re‐use of fracturing fluids is being evaluated by service companies and 

operators to determine the degree of treatment and make‐up water necessary for re‐use. The practical 

use of on‐site, self‐ contained treatment facilities and the treatment methods employed will be dictated 

by flow rate and total water volumes to be treated, constituents and their concentrations requiring 

removal, treatment objectives and water reuse or discharge requirements. In some cases it would be 

more practical to first treat the water to a quality that could be reused for a subsequent hydraulic 

fracturing job, or other industrial use, rather than treating to discharge to a surface water body or for 

use as drinking water. 


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In Section 6.2 – Comprehensive Water Management, we presented detailed information about water 

treatment options and their costs. 

4.7.5 Naturally Occurring Radioactive Material (NORM) 

Some soils and geologic formations contain low levels of radioactive material. This naturally occurring 

radioactive material (NORM) emits low levels of radiation, to which everyone is exposed on a daily basis. 

Radiation from natural sources is also called background radiation. 

In addition to the background radiation at the earth’s surface, NORM can also be brought to the surface 

in the natural gas production process. When NORM is associated with oil and natural gas production, it 

begins as small amounts of uranium and thorium within the rock. These elements, along with some of 

their decay elements, notably radium226 and radium228, can be brought to the surface in drill cuttings 

and produced water. Radon222, a gaseous decay element of radium, can come to the surface along with 

the shale gas. 

When NORM is brought to the surface, it remains in the rock pieces of the drill cuttings, remains in 

solution with produced water, or, under certain conditions, precipitates out in scales or sludges. The 

radiation from this NORM is weak and cannot penetrate dense materials such as the steel used in pipes 

and tanks. 

Figure 4-73. Drilling pipe can become NORM contaminated 

The principal concern for NORM in the oil and gas industry is that, over time, it can become 

concentrated in field production equipment and as sludge or sediment inside tanks and process vessels 

that have an extended history of contact with formation water. Because the general public does not 

come into contact with oilfield equipment for extended periods, there is little exposure risk from oilfield 


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NORM. Studies have shown that exposure risks for workers and the public are low for oil and gas 

operations. 

The handling (re-use) and disposal of NORM‐contaminated equipment, produced water, and oil‐field 

wastes should be performed in compliance with Dutch regulations. While NORM may be encountered 

in shale gas operations, there is negligible exposure risk for the general public and there are well 

established regulatory programs that ensure public and worker safety. 

4.7.6 Pollution Prevention 

The best way to reduce pollution is to prevent it in the first place. The oil & gas industry has been 

aggressively implementing pollution prevention procedures that improve efficiency and increase profits, 

while at the same time minimizing environmental impacts. 

Within the O&G, when discussing pollution prevention you’ll consistently hear the phrase – Reduce, 

Replace, and Re-use: 

• Reduce – develop processes, practices or products or eliminate the generation of pollutants and 

wastes 

• Replace – look for alternative products (substitution and composition) which have less of an 

environmental impact 

• Re-use – once is never enough – look for opportunities to recycle O&G waste 

4.7.7 Best Management Practices (BMPs) 

Utilizing BMPs to contain, control and clean up fluids used throughout drilling and collection operations 

helps to minimize the potential for reportable spills and adverse environmental impact, and mitigate any 

possible contamination from these processes. 

Numerous industry groups recommend that spill prevention, response and clean-up procedures for 

storing oils, chemicals and other fluids be part of the Standard Operating Procedures (SOP) manual at all 

sites. These recommended practices include using dikes and walls around tanks, using secondary 

containment basins and liners, and using absorbents between sites and surface waters. 

In the Marcellus Shale Coalition's (MSC) Best Practices for Drilling and Well Construction & Best Practices 

Well Completion and Work-over Operations documents, the following recommendations are made: 

• Waste management strategy should include storage containment, spill contingency plans, 

transfer and disposal procedures 

• Secondary containment should be provided for fuel storage containers and areas 

• Drilling fluid tanks and manifolds should be considered for placement inside lined secondary 

containment areas 

• Drilling fluid containment and catchment systems should be considered 


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In order to keep sediment and other liquid pollutants (oils, chemicals) out of surface waters, establishing 

a perimeter to prevent fluid and sediment migration, and providing containment pads, liners, barriers 

and covered storage units is essential. 

4.7.8 Stormwater Management Plans 

The management of stormwater associated with a rainfall event is a critical component of any pollution 

prevention program. The objective of stormwater management is to prevent or mitigate the adverse 

impacts related to the conveyance of excessive rates and volumes of stormwater runoff. 

The effectiveness of a given stormwater management program is a function of comprehensive planning 

and sound engineering design. The intent is to develop a plan which facilitates natural runoff flow 

characteristics either by augmenting the infiltration process or by temporarily storing stormwater for 

release at controlled rates of discharge. This can be accomplished by implementing stormwater 

management techniques which are either structural (detention ponds, pipes, etc.) or nonstructural 

(land-use planning to effectively preserve existing vegetation, drainage swales, perviousness, etc.). Both 

techniques should be utilized as complementary elements of a management plan. 

Figure 4-74. Typical retention basin used for stormwater management 

Stormwater plans should include: 

• A survey of existing runoff characteristics in small as well as large storms, including the impact of 

soils, slopes, vegetation and existing development; 

• A survey of existing significant obstructions and their potential impacts; 

• An assessment of projected development at the site and the potential impact of runoff quantity, 

velocity and quality; 

• An analysis of projected development in the flood hazard areas, and its sensitivity to damages 

from future flooding or increased runoff; 

• Survey of existing drainage problems; 


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• A plan site stormwater collection systems and their capacities; 

• An assessment of alternative runoff control techniques and their potential benefits; and 

• Provisions for periodically reviewing, revising and updating the plan. 

Erosion and Sediment Control Plan 

Utilizing BMPs to contain, control and clean up fluids used throughout drilling and collection operations 

helps to minimize the potential for reportable spills and adverse environmental impact, and mitigate 

contamination from these processes. 

4.7.9 Erosion and Sediment Control Plan 

An Erosion and Sediment Control Plan is intended to help manage the potential impacts from shale gas 

development activities upon the natural conditions of the site. Sediments washing into streams are one 

of the biggest potential water quality problems associated with construction activities related to shale 

gas development projects. 

Each plan should be developed with sections addressing the following components: 

• Pre-construction Planning 

• Overview of Construction Phase Operations 

• Diverting Upland Run-off Around Exposed Soils 

• Protecting Soils with Seed, Mulch or Other Products 

• Using Silt Fences and Other Sediment Barriers 

• Protecting Slopes to Prevent Gullies 

• Protecting Culverts and Ditch Inlets and Outlets 

• Stabilizing Drainage Ditches 

• Installing Sediment Traps and Basins 

• Protecting Stream Channels, Wetlands and Lakes 


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Figure 4-75. Silt fence used as an erosion and sediment control device 

4.7.10 Spill Prevention Plans 

Operators strive to operate their facilities in a safe and environmentally responsible manner but 

recognize that there will be instances in which certain products will be spilled. With that understanding 

in mind, they proactively develop spill response plans which they implement when a spill occurs. Some 

of the components of these plans include: 

• A formal written plan 

• Identification of responsibilities 

• Regulatory notification requirements 

• Emergency contact numbers 

• Facility map 

• Site inventory of possible hazards 

• Spill containment procedures 

• Sampling of media (air, water & soils) procedures 

• Pre-qualification of emergency response contractors and suppliers 

• Training / auditing requirements 

• Verification of response activities 


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Figure 4-76. Spill response equipment 

The implementation of BMPs and the use of the proper spill containment products can help the 

Operator limit the impacts of spills and help to quickly clean-up the area should one occur. 


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4.8 Well Containment 

One of the biggest concerns related to the technologies for developing shale gas wells through the use 

of horizontal drilling and hydraulic fracing has to do with the potential for contamination of water 

supplies, particularly drinking water aquifers. 

The O&G industry places great emphasis on protecting groundwater. Current well construction 

requirements consist of installing multiple layers of protective steel casing and cement that are 

specifically designed and installed to protect fresh water aquifers and to ensure that the producing zone 

is isolated from overlying formations. During the drilling process, a conductor and surface casing string 

are set in the borehole and cemented in place. In some instances, additional casing strings may be 

installed; these are known as intermediate casings. After each string of casing is set, and prior to drilling 

any deeper in the borehole, the casing is cemented to ensure a seal is provided between the casing and 

formation or between two strings of casing. 

This illustration depicts how the casing and cement that may be installed in shale gas wells and 

highlights how the casing can be set to isolate different water‐ bearing zones from each other. 

Figure 4-77, Diagram of well casing for horizontal well 

The drawing shows the multiple strings of casing, layers of cement and the production tubing, which are 

all important parts of the well completion in preventing contamination of fresh water zones and 

assuring that the gas resource does not flow into other, lower pressure zones around the outside of the 

casing rather than flowing up the well to be produced and sold. 


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The conductor casing serves as a foundation for the well construction and prevents caving of surface 

soils. The surface casing is installed to seal off potential freshwater bearing zones. This isolation is 

necessary in order to protect aquifers from drilling mud and produced fluids. As a further protection of 

the fresh water zones, air‐rotary drilling is often used when drilling through this portion of the wellbore 

interval to ensure that no drilling mud comes in contact with the fresh water zone. Intermediate 

casings, when installed, are used to isolate non‐ freshwater‐bearing zones from the producing wellbore. 

Intermediate casing may be necessary because of a naturally over‐pressured zone or because of a 

saltwater zone located at depth. The borehole area below an intermediate casing may be un-cemented 

until just above the kickoff point for the horizontal leg. This area of wellbore is typically filled with 

drilling muds. 

Each string of casing serves as a layer of protection separating the fluids inside and outside of the casing 

and preventing each from contacting the other. Operators perform a variety of checks to ensure that 

the desired isolation of each zone is occurring including ensuring that the casing used has sufficient 

strength, and that the cement has properly bonded to the casing. These checks may include acoustic 

cement bond logs and pressure testing to ensure the mechanical integrity of casings. Additionally, 

regulatory agencies often specify the required depth of protective casings and regulate the time that is 

required for cement to set prior to additional drilling. These requirements are typically based on 

regional conditions and are established for all wildcat wells and may be modified when field rules are 

designated. Once the casing strings are run and cemented there could be five or more layers or barriers 

between the inside of the production tubing and a water‐bearing formation (fresh or salt). 

4.8.1 API Research 

Analysis of the redundant protections provided by casings and cements was presented in a series of 

reports and papers prepared for the American Petroleum Institute (API) in the 1980s. These 

investigations evaluated the level of corrosion that occurred in Class II injection wells. Class II injection 

wells are used for the routine injection of water associated with oil and gas production. The research 

resulted in the development of a method of calculating the probability (or risk) that fluids injected into 

Class II injection wells could result in an impact to drinking water. This research started by evaluating 

data for oil and gas producing basins to determine if there were natural formation waters present that 

were reported to cause corrosion of well casings. The United States was divided into 50 basins, and 

each basin was ranked by its potential to have a casing leak resulting from such corrosion 

Detailed analysis was performed for those basins in which there was a possibility of casing corrosion. 

Risk probability analysis provided an upper bound for the probability of the fracturing fluids reaching an 

underground source of drinking water. Based on the values calculated, a modern horizontal well 

completion in which 100% of the USDWs are protected by properly installed surface casings (and for 

geologic basins with a reasonable likelihood of corrosion), the probability that fluids injected at depth 

could impact a USDW would be between 2 x 10‐ 5 (one well in 200,000) and 2 x 10‐ 8 (one well in 

200,000,000) if these wells were operated as injection wells. Other studies in the Williston basin found 


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that the upper bound probability of injection water escaping the wellbore and reaching an underground 

source of drinking water is seven chances in one million well‐years where surface casings cover the 

drinking water aquifers. 

These values do not account for the differences between the operation of a shale gas well and the 

operation of an injection well. An injection well is constantly injecting fluid under pressure and thus 

raises the pressure of the receiving aquifer, increasing the chance of a leak or well failure. A production 

well is reducing the pressure in the producing zone by giving the gas and associated fluid a way out, 

making it less likely that they will try to find an alternative path that could contaminate a fresh water 

zone. Furthermore, a producing gas well would be less likely to experience a casing leak because it is 

operated at a reduced pressure compared to an injection well. It would be exposed to lesser volumes of 

potentially corrosive water flowing through the production tubing, and it would only be exposed to the 

pumping of fluids into the well during fracture stimulations. 

The API study included an analysis of wells that had been in operation for many years when the study 

was performed in the late 1980s, and does not account for advances that have occurred in equipment 

and applied technologies and changes to the regulations. As such, a calculation of the probability of any 

fluids, including hydraulic fracture fluids, reaching a USDW from a gas well would indicate an even lower 

probability; perhaps by as much as two to three orders of magnitude. The API report came to another 

important conclusion relative to the probability of the contamination of a USDW when it stated that: 

For injected water to reach a USDW in the 19 identified basins of concern, a number of independent 

events must occur at the same time and go undetected. These events include simultaneous leaks in the 

[production] tubing, production casing, [intermediate casing,] and the surface casing coupled with the 

unlikely occurrence of water moving long distances up the borehole past salt water aquifers to reach a 

USDW. 

As indicated by the analysis conducted by API and others, the potential for groundwater to be impacted 

by injection is low. It is expected that the probability for treatable groundwater to be impacted by the 

pumping of fluids during hydraulic fracture treatments of newly installed, deep shale gas wells when a 

high level of monitoring is being performed would be even less than the 2 x 10‐ 8 estimated by API. 

In addition to the protections provided by multiple casings and cements, there are natural barriers in the 

rock strata that act as seals holding the gas in the target formation. Without such seals, gas and oil 

would naturally migrate to the earth surface. 

A fundamental precept of oil and gas geology is that without an effective seal, gas and oil would not 

accumulate in a reservoir in the first place and so could never be tapped and produced in usable 

quantities. These sealing strata also act as barriers to vertical migration of fluids upward toward useable 

groundwater zones. 


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Figure 4-78. Representation of drinking water tables in relation to shale gas drilling operations 


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5 Summary and Recommendations 

EBN and all other operators need to consider a strategy how to develop Shale Gas prospects with a 

public acceptance and following all the necessary environmental regulations and laws.. Furthermore, we 

strongly recommend EBN to work out a more detailed and comprehensive well plan, i.e. perform 

collaborative well planning on both Boxtel and Haaren wells to seek a technical optimal and socially and 

environmentally acceptable placement of the wells. 

G&G Summary 

All available well evaluation data, mudlogs, sample analysis, and petrophysical well logs, support the 

conclusion that the Posidonia and Aalburg shales are organic rich source shales. Of the two, the 

Posidonia looks to have the best chance of being oil or gas condensate productive because it 

demonstrates higher effective porosity. It also exhibits a much lower structural dip than the Aalburg. 

That relatively flat dip is required for any kind of potential horizontal well development. 

Calculated mechanical properties of the Posidonia support it being a very soft and ductile shale that, 

while easy to frac, will make it difficult to establish a lot of effective conductivity by induced fracture 

complexity. Proppant conductivity can also be severely compromised by fines embedment in such a soft 

shale if subjected to very high differential draw down pressures. 

The wild card for enhanced productivity, even though it is a soft shale, appears to be the fact that the 

Posidonia overlays a series of numerous faults in a very tectonically active geologic basin. The stress field 

generated from these faults immediately below the optimum porosity interval should result in a shale 

that is potentially naturally fractured with enough fracture aperture for enhanced fluid delivery and 

migration. The existence of the lower faults also will prove to be a geo-hazard if not mapped adequately 

prior to horizontal development. 

A small number of vertical test, or pilot, wells drilled expressly for evaluation of the Posidonia & Aalburg 

shales should be drilled prior to a full-on horizontal development project. A complete modern shale 

petrophysical analysis should be performed that would link full core data with modern geochemical well 

logs and three dimensional stress measurements for optimum target delineation and optimized fracture 

design. 

Vertical well(s) and/or test horizontal well(s) should also be test fractured to establish exact pore 

pressure, closure stress, and leakoff parameters for optimized fracture design in a development phase. 

Many of the techniques discussed in this paper have proven successful in North America. 

With this being said, the completion recommendation for EBN is to adopt the third technique – coiledtubing 

assisted fracturing and more specifically HydraJetting via coiled-tubing. This method facilitates 

stimulating multiple shale intervals with less than half the hydraulic horsepower requirements and a 

significantly reduced footprint compared with other currently popular completion methods. This 

technology has significant potential because coiled tubing and HWO units are available in Europe. The 


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pinpoint stimulation coiled-tubing method is environmentally friendly from a surface standpoint as its 

HHP, footprint, and water usage is much lower than the other two primary completion methods while 

maintaining its competitive performance. 

Hydraulic Fracture Design Summary 

(Refer to 3.2.4 Hydraulic Fracture Summary and Recommendations) 

Production Forecasting Summary 

(Refer to 3.3.3 Summary and Recommendations) 

Drilling Summary 

Final lateral lengths for planning need to be finalized based on the economic frac intervals required for a 

successful horizontal well. 

Well designs other than the standard vertical, build and horizontal need to be agreed on. 

The kick off points (KOPs) are presently being planned from 2150m to 2900m. The more complex well 

designs are feasible but require the KOPs to be higher in the well. 

Additional pad location screening needs to be carried out to determine acceptable definitive pad 

locations for further use in planning. 

Completion Summary 

The most common completion techniques seen in shale gas completion in the United States today are: 

• Plug and perf technique using drillable bridge plugs for isolation; 

• Ball drop or remote actuated sliding sleeve completions using open-hole packers in 

uncemented applications or cemented into place; and 

• Coiled-tubing assisted fracturing using HydraJet perforating and sand plugs for zone isolation. 

Transporting these techniques across the Atlantic into the European market may not be a very 

straightforward process. The concern with two of those three methods (plug and perf and sliding 

sleeves) is that they generally require very high pump rates and significant amounts of fracturing 

horsepower on location. 

One additional limitation that needs to be addressed for the European market is also rig availability. 

One estimate is that nearly 75% of the service industry’s global pressure-pumping equipment currently 

resides in North America. This could potentially have a large impact on shale play from exploration to 

development progress in Europe. 


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Notional Field Development Final Report - EBN

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