FINAL REPORTHigh Impact Systems(Rock Bits, Coring & More)
Technical Review & Risk
Reduction Study
for theBEAM ‐ Borehole into Earth's
Mantle Mantle Quest Drilling
Project

Prepared For:
Yoshi Kawamura
Integrated Ocean Drilling Program –Management International
Purpose:Identify, Provide Technical Review, andPropose Risk Reduction Process for
Equipment & Services, such as Rock Drill Bits
and Coring Systems to Substantially Reduce
Mantle Drilling Time & Risk.

Version:003
2600 Network Boulevard, Suite 550
Frisco, Texas 75034+1 972‐712‐8407 (phone)+1 972‐712‐8408 (fax)Date:
7 February 2013

Project Number:
IOD‐I212‐002

www.blade‐energy.com

Blade Energy Partners Limited, and its affiliates (‘Blade’) provide our services subject to our General Terms and Conditions (‘GTC’) in effect at time of service, unless a GTC
provision is expressly superseded in a separate agreement made with Blade. Blade’s work product is based on information sources which we believe to be reliable, including
information that was publicly available and that was provided by our client; but Blade does not guarantee the accuracy or completeness of the information provided. All
statements are the opinions of Blade based on generally-accepted and reasonable practices in the industry. Our clients remain fully responsible for all clients’ decisions, actions
and omissions, whether based upon Blade’s work product or not; and Blade’s liability solely extends to the cost of its work product.

BEAM Project – High Impact Systems, Technical Review and Risk Reduction Study

Version Record
Version
No.

Issue
Date

Issued As /Nature of Revision

AuthorChecked By

Project000

17 Dec 2012

Draft

WSW/NP

BP

BP

001

23 Dec 2012

Draft

WSW/NP

BP

BP

002

14 Jan 2013

Draft

WSW/NPBPBP

7 Feb 2013

Final after IODP review
and comment

WSW/NP

BP

BP

003

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Table of Contents
1
2

Executive Summary.............................................................................................................. 6
Overview of Hard Rock Drilling............................................................................................. 8
2.1
Overview of Drilling Bit Systems – Definition ................................................................ 8
2.2
Bit Types and Rock Failure Mechanism ....................................................................... 8
2.2.1
Tungsten Carbide Inserts (TCI) and Tricone Bits ................................................. 92.2.2
PDC Bits ............................................................................................................... 9
2.2.3
Insert Bits and Impregnated Diamond Drill Bit .................................................... 10
2.2.4
Roller Cone Bits .................................................................................................. 10
2.2.5
Discussion........................................................................................................... 11
2.3
Bit Materials ................................................................................................................ 11
2.4
Rock Classification...................................................................................................... 12
2.5Rock Properties .......................................................................................................... 13
2.5.1
Generality............................................................................................................ 13
2.5.2
Discussion on Strength Properties...................................................................... 14
2.6
Drilling Efficiency in Hard Rocks ................................................................................. 16
2.7
Hard Rock Drilling Industry Experience ...................................................................... 16
2.8
Hard Rock Bit Selction Criteria ................................................................................... 18
2.9
Conclusions ................................................................................................................ 19
3
Review of Hard Rock O&G Drilling Services ...................................................................... 20
4
Revised BEAM Operational Time Estimate ........................................................................ 24
4.1
Review of NOV 1256D Core Testing .......................................................................... 24
4.2
2011 Feasibility Study Operational Time Estimate Review ........................................ 25
4.3
2012 Revised Operational Time Estimates................................................................. 26
5
Potential Issues with High Temperature and Down-hole Tools .......................................... 33
5.1
Overview ..................................................................................................................... 33
5.2
Estimated Down-hole Temperature ............................................................................ 33
5.3
Review of Current O&G Industry Capabilities............................................................. 35
5.3.1
Summary of Service Company Meetings............................................................ 35
5.3.2
Standard Temperature Tools .............................................................................. 365.3.3
High Temperature Tools ..................................................................................... 36
5.3.4
Developmental Effort / Trends ............................................................................ 38
5.3.5
Discussion........................................................................................................... 39
5.4
Marine Drilling Riser.................................................................................................... 39
5.4.1
Summary of Service Company Meetings............................................................ 39
5.4.2
Discussion........................................................................................................... 43
5.4.3
Riser Options Review ......................................................................................... 44
5.4.4
Pro’s and Con’s Comparison .............................................................................. 45
5.5
Review of Survey Services ......................................................................................... 45
5.5.1
Metocean Survey ................................................................................................ 45
5.5.2
Geohazards Survey ............................................................................................ 47
5.6
Expandable Casing..................................................................................................... 47
6
Conclusions and Recommendations .................................................................................. 49
7
Main References................................................................................................................. 50
Appendix 1: BEAM Followup Questionnaire (generic) ............................................................... 52
Appendix 2: 1256D Core Test Report ........................................................................................ 54
Appendix 3: Base Case Well Configuration................................................................................ 55
Appendix 4: Glossary of Terms ................................................................................................. 56

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Table of Figures
Figure 1. PDC Formation Failure Mechanism: Shear................................................................... 9
Figure 2. Diamond Impregnated Formation Failure Mechanism: Grind and Shear.................... 10
Figure 3. Rolling Cutter Formation Failure Mechanism: Compression ....................................... 11
Figure 4. Classification of Igneous Rocks .................................................................................. 12
Figure 5. Depiction of the Geomechanical State of Stress ......................................................... 14
Figure 6. Hybrid PDC-Impreg Bit Used to Drill Hard Carbonate Formation Deepwater Canada 16
Figure 7. Impreg Bit for Drilling Basalt Offshore Shetland .......................................................... 17
Figure 8. 12-1/4” PDC MDSi816LBPX with ONYX Cutters ........................................................ 17
Figure 9. Illustration of Halliburton’s Coring Experience............................................................. 21
Figure 10: NOV 1256D UCS Core Test Results Summary ........................................................ 24
Figure 11: Case 2 - 2011/2012 Drilling Curve Comparison ....................................................... 29
Figure 12: Case 4 2011/2012 Drilling Curve Comparison ......................................................... 32
Figure 13. High Pressure and High Temperature Tools (modified from SPE and Halliburton) .. 33
Figure 14. Estimated Bottom-hole Temperature for Three Candidate Locations ....................... 34
Figure 15: Expandable Casing Example .................................................................................... 48
Figure 16: Base Case Mantle Well Configuration....................................................................... 55

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List of Tables
Table 1. Examples of Mechanical Properties for Hard Sedimentary, Metamorphic and IgneousRocks.......................................................................................................................................... 15
Table 2 - Service Company Capability Summary ....................................................................... 22
Table 3: Estimated Ideal ROP’s Based on Current Technology................................................ 25
Table 4: 2011 Feasibility Study Operational Time Estimates Summary..................................... 26
Table 5: 2012 Operational ROP’s.............................................................................................. 26
Table 6: Hawaii - Case 2 – 2012 Revised Operational Time Estimate....................................... 27
Table 7: Hawaii - Case 2 - 2011 Feasibility Study Operational Time Estimate ......................... 28
Table 8: Hawaii - Case 4 - 2012 Revised Operational Time Estimate ....................................... 30
Table 9: Hawaii - Case 4 - 2011 Feasibility Study Operational Time Estimate .......................... 31
Table 10. Standard Pressure / Temperature Down-hole Tool Ratings....................................... 37
Table 11. High Pressure / Temperature Down-hole Tool Ratings .............................................. 37
Table 12. Current High Temperature Down-hole Tool Development ......................................... 38
Table 13. Materials for Marine Drilling Risers............................................................................. 44
Table 14. Nine Possible Configurations for Drilling Risers to Reach Ultra-Deepwater .............. 44
Table 15. Advantages and Drawbacks for the Nine Drilling Riser Options ................................ 45

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1 Executive Summary
In 2011 Blade conducted an initial high-level mantle drilling feasibility study which showed thatwith existing technologies it is feasible to core/drill a hole into the mantle at a Pacific Ocean
location using IODP's Chikyu drillship with some equipment modifications. However, the drilling
time (depending upon location) in 3650 - 4300m water to 9900 - 10750m total depth could take418 - 934 days (depending upon operational choices). Considering deepwater drilling today
may be generally estimated as a US$1Million/day cost, any reduction in drilling days
proportionately reduces both the project cost and the project operational risk. The feasibility
study indicated that such a world-record deep well would require 36-48% of project time making
bit trips (pulling out of hole, changing a worn bit, then running back in the hole to bottom) and13-25% of project time coring. If the time for either fewer bit trips or coring can be shortened
and made more efficient by application of new technologies, then significant savings in projecttime will result, and a commensurate reduction in project risk will also result.
In February 2012, IODP-MI requested that Blade conduct study to identify and investigate
equipment and services that could substantially decrease drilling time and risk when drilling toearth's mantle.
The objectives of this study were to identify the original equipment
manufacturers and service companies that provide rock drill bits and coring, and investigate thestatus of their technologies today, what technological improvements they may reveal for mantle
quest application by 2017, and what suggestions they offer to accelerate technologicaldevelopment between now and 2017.
More specifically, the goals of study were to address the following:•

Review the mechanics of hard rock drilling.

•

Identify current rock drill bit equipment and services.

•

Investigate potential technological gaps and improvements that will enable rock drill bits tostay on-bottom longer, decreasing drilling time and risk.

•

Identify current rock coring systems and services.

•

Investigate possible development of new rock coring systems to improve the quality andquantity of cores recovered in order to satisfy the scientific objectives.

•

Provide a recommendation of the most efficient and most viable drill bits and rock coring
systems for a possible mantle quest drilling project spud date in 2017-2018.

•

Provide an estimate of how the designers, manufacturers, and service companies of such
equipment and services may accelerate their technological offerings, including an estimateof the technological improvement costs to IODP and the scientific community.

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Identify additional high-impact equipment and services where technological improvements
will also reduce project time and risks.

The results of this effort are described in this report. Blade had extensive discussions with 19
different service companies that provide a wide range of services to the oil and gas industry.
The key conclusion for this study is that the oil and gas industry has wide experience drilling andcoring high temperature hard rocks - including basalt. And the operational time and risks
associated with drilling a hole to the mantle can be significantly reduced by capitalizing on thisexperience.

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2 Overview of Hard Rock Drilling
Many tools are available to enable the drilling process in order to penetrate a given geologicalformation. The majority of the drilling systems utilize a type of mechanical drill (e.g. drilling bit for
rotary drilling) which is used to apply either cutting or breaking forces over a small contact
surface on the rocks. Hence, the cutting or breaking forces generally generate stresses thatexceed either the rock tensile strength or the rock shear strength. As a result, rocks will either
fail due to brittle failure or plastic yielding.
Note that even though mechanical processes account for a large part of the methods used tobreak rocks, two other approaches could also be used to fail rocks. The first alternative method
is thermal loading using either spallation, melting or vaporization processes and the second
method can use chemical agents to react with the rock surface.

2.1 Overview of Drilling Bit Systems – Definition
One of the most important parts of the mechanical process such as the rotary drilling system
which is widely used by energy industry is called the drill bit. Actually, because of the various
situations that can be encountered during rotary drilling operations, a very large catalogue ofbits can be manufactured to reach optimum performance when drilling different geologicallayers.
A drill bit can be defined as a mechanical component constituting the end of the drill-string andthat can not only drill the desired borehole diameter but also, because of its design, has a direct
impact on the characteristics of the core, rock fragments and cuttings that are recovered fromthe borehole being drilled. As stated previously, a drill bit can come in various forms and sizes
using different cutting surfaces and also its body can be composed of different materials.

2.2 Bit Types and Rock Failure Mechanism
The range of drill bits available within the petroleum industry is vast and has significantly
increased over the last two decades as a result of the development of new cutter elements suchas polycrystalline diamond. Thus, depending upon the type of geological layer and the formation
geotechnical and petrophysical characteristics (e.g. hardness, abrasively, strength, etc…) a
certain drill bit type and design will be selected.
Thus, there are “soft rock drill bits” that are specifically designed to drill through soft formations
and also there are “very hard formation rock bits” to enable drilling through hard formations suchas hard shale or carbonates which are often encountered by the oil and gas industry but; there
are also hard igneous rocks. Usually, one can distinguish four main types of drill bit systems thatcan be used in well or borehole drilling.

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2.2.1 Tungsten Carbide Inserts (TCI) and Tricone Bits
In a tungsten carbide insert bit, the load is applied to a cutter and the pressure beneath thecutter increases until it exceeds the crushing strength of the rock. Then, a wedge of finely
powdered rock is formed beneath the cutter. Consequently, as the force on the cutter increases,
the material in the wedge compresses and exerts high lateral forces on the rock surrounding thewedge. Finally, the shear stress will exceed the shear strength of the rock and the rock will
fracture and eventually fail.
Tricone bit systems have per definition three cones. These cones can rotate around the drill bit
axis. If the tricone bit has been designed with longer and more widely arranged teeth, it isintended to drill relatively soft formations. Conversely, if the tricone bit has been designed withshorter and more closely arranged teeth, it will preferably be used to drill harder formations.
Also, note also that in general, drill bit systems having shorter teeth drill through the rock muchslower than bit systems having longer teeth. In addition, some simpler bit design can be madewith single or dual cones instead of tricones.

2.2.2 PDC Bits
Polycrystalline diamond compact bits (i.e. PDC) consist of polycrystalline diamond compact
buttons inserts that are used to break the rock with a shearing mechanism but until recently
have been known and used to penetrate through relatively soft rocks. Nowadays, PDC bits canbe used in a lot of drilling applications. With PDC bit systems, the high abrasion resistance ofthe diamond layer is used to remove the different layers composing the rock by a shearing
action. Additionally, PDC bits are also partly made with tungsten carbide cylinder. The tungsten
carbide layer is used to provide mechanical support and high resistance to impact loading. Also,
since PDC bits are built in a mold with the compacts positioned prior to pouring the metallic
compound, the design of PDC bits can be almost unlimited.

Figure 1. PDC Formation Failure Mechanism: Shear

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2.2.3 Insert Bits and Impregnated Diamond Drill Bit
Insert bits are also called surface set diamond bits. These bit systems consist of several single
diamonds which have been set in the metallic body matrix. They are utilized to drill through very
hard formations.
Impregnated diamond drill bit. These drill bit systems are specifically designed for ultra-hard,abrasive rock formations. This bit design consists of a diamond grit which is mixed with tungsten
carbide in its liquid form. Then, the mixed compound is molded into the bit design shape. The
wear resistance of impregnated bits is of particular importance to drill through abrasive
formations (e.g. relatively high silica, quartz or iron content).

Figure 2. Diamond Impregnated Formation Failure Mechanism: Grind and Shear.

2.2.4 Roller Cone Bits
Roller cone bits are made of “wheels” with teeth that rotate or turn when the bit is being rotated.
The bit teeth apply a pressure level onto the rock that exceeds the formation strength and hence
the rock is failed in compression. The cones roll about the bottom of the borehole as the bit
rotates. Note that the three cones cutter bit is the most common bit type currently used with therotary drilling process. Additionally, roller cone bits are available with numerous cutter designs
and bearing types to be used to drill a wide range of geological formations.

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Figure 3. Rolling Cutter Formation Failure Mechanism: Compression

2.2.5 Discussion
Depending on the location of the drill bit within the rock material, rocks can be broken under
tensile, shear or compressive stresses. Tension and shear stresses induce failure of the intergranular bonds and pure compressive stresses lead to crushing and breakage of the rockgrains. Also and more importantly, these stresses can also be influenced by the bit design as
discussed previously, but equally, the borehole geometry and the drill-string dynamics can playa critical part in the rock failure mechanism.
Additionally, bit design is also critical when trying to drill a directional borehole, or when trying tomaintain or drill a vertical borehole. The borehole trajectory is essentially controlled by two
parameters: the bit tilt and the side forces acting on the bit which are notably a function of the bit
type, ROP, bottom hole assembly and rock characteristics, and geology (dipping beds, etc).
These two parameters define the direction of the bit force, hence the borehole trajectory.

2.3 Bit Materials
The materials that are used to build drill bit systems are critical for drill bits performance,
durability and their specific application. The materials used are usually hardened and tempered
carbon steel, cobalt steel and tungsten carbide. Also, for some bit designs, single diamond
crystals can be embedded into the tips of the cutting tools. However, since single diamond
crystal have large strength anisotropy and are very brittle when impacted at some angles, they
are often fused together to form a polycrystalline diamond and bonded to a tungsten carbide
mixed compound. Also, because of this change in crystalline structure in the presence of certain
metals and its tendency to revert to graphite when used to drill very hot formations, coatings
such as black oxide, titanium carbon nitride (TiCN) or zirconium nitride are applied on the
diamonds in order to increase bit wear resistance.

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2.4 Rock Classification
Geological formations can be classified into three categories:
1. Sedimentary;
Sedimentary rocks are composed of individual mineral or lithic fragments that have beentransported and deposited in layers. These layers or strata have been compacted or
cemented to form a rock.
2. Metamorphic;
Metamorphic rocks are either igneous or sedimentary rocks that have been altered byheat and/or pressure during their burial. The original rock textures and mineral
assemblages have been progressively replaced.
3. Igneous.
In this study and because of the nature of the rocks that have been drilled at IODP hole
1256D, 504B, U1309D and 735B and that are expected to be drilled and cored whendrilling to the upper mantle, igneous rocks are the one that will be essentially discussed
in this study.
Igneous rocks are geological layers that have solidified from a molten state. Indeed,basalt is one of the best examples of an igneous rock. Igneous rocks can either haveglassy aspect when quickly cooled, or have been fully crystallized if the cooling has been
relatively slow. One can distinguish four main types of igneous rocks: granite, diorite,
gabbro (i.e. basalt) and peridotite which actually depend on the silica, magnesium andiron composition.

.
Figure 4. Classification of Igneous Rocks

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2.5 Rock Properties
2.5.1 Generality
Rock behavior to any external loading depends not only on the magnitude of the loads applied
but also on the rock physical and mechanical properties. One can distinguish three rockproperty categories:
1. Elastic properties;
Young’s modulus, shear modulus, bulk modulus, Poisson’s ratio, bulk compressibility, andgrain or matrix compressibility constitute rock elastic properties and enable to define rocks
elastic deformation when a rock is submitted to a given loading condition.
2. Strength properties;
The rock strength properties are used to describe the maximum loading that a rock can
withstand before yielding and can also describe the rock plastic behavior when the loading
is pushed beyond the rock elastic capacity. There are several strength variables andparameters that can be used: cohesive strength, tensile strength, compressive strength andinternal friction angle for sedimentary rocks.
a. Shear strength is the maximum shear stress that a rock can sustain. The resistive
forces come from both the cohesive resistive force and the frictional resistive force.
Cohesion comes notably from mineral cementation from quartz, calcareous, andcohesive bonding such as capillary force.
b. Uniaxial compressive strength (UCS) is the maximum stress that a rock can
withstand during a uniaxial compression test with when the confining stress is nil.
The rock will be assumed to be more stable when drilled through if its UCS is higher
but it will be much harder to drill through. When conducting UCS test, cylindricalsamples with Length to Diameter ratio of 2:1 are prepared from good quality coresamples. The samples are mounted in a compression frame and submitted to anincreasing compressive load applied. The common practice is to calculate theaverage of five UCS tests from the same stratigraphic column.
Note also that UCS can be estimated from formation bulk compressibility, shear andcompressive sonic velocities or gamma ray data from an offset borehole. In addition,in order to complement the UCS test, other penetration tests such as the elastic
rebound tests, the point load test and core scratch test can provide an additional andcontinuous strength estimate.
c. Rock residual strength is the strength of the rock has after the rock has lost its
cohesive strength component and original structure integrity. This strength isimportant in order to predict the rock post-failure behavior. Note that for both

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sedimentary and igneous rocks, there is a difference between the strength of theintact rock sample and the strength of the rock individual mineralogical constituents.
d. Triaxial test is often considered as the most reliable approach to determine rockstrength when testing core samples in the laboratory. To perform this test, between
three and five cylindrical samples with Length over Diameters equals to 2/1 are used
to calculate the Mohr Coulomb yield criterion over a wide range of stresses.
Rock strength properties are particularly influenced by numerous internal parameters suchas rock anisotropy, mineral grain size, mineral cement type, original cracks and fissures,
and also external criteria such as the state of stress, loading path and water saturation.

Figure 5. Depiction of the Geomechanical State of Stress
3. Transport properties.
Rock porosity and permeability are the two commonly used properties to describe theability of a fluid to migrate through a rock.
Also, note that elastic, strength and transport rock properties are not independent are related toeach other directly or indirectly. For instance, rocks with high tensile strength are likely to havehigh Young modulus, low Poisson’s ratio, and low porosity. In this study, emphasis has been on
looking in great details at rock strength properties and particularly igneous compressive
strength. Finally, in practice, cores and core fragments will be tested by one or several of thetests previously discussed.

2.5.2 Discussion on Strength Properties
When subject to external loading, rock may lose its integrity if the applied force exceeds therock strength. The mechanical strength of rock is its most crucial property and; as discussed
previously can be assessed by testing its shear strength, uniaxial compressive strength (i.e.
UCS), tensile strength, and residual strength.

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Additionally, rock properties may vary quite significantly under different internal and external
conditions. In general, rock strength increases as depth increases. However, this increase instrength may be balanced back when local over-pressurization of the fluids are present within
the rocks; thus, resulting in reduced effective stresses. Note that an increasing confining stresswill have notably two effects:
a. First, an increase in rock compressive strength (UCS). Also, note that both elastic andstrength properties increase drastically when confining stresses increase.
b. Secondly, a reduction of the brittle characteristics of the stress–strain curve which will
decrease the rock tendency to expand (i.e. dilatation).
Furthermore, another criterion that may affect rock strength is formation temperature. Becauseof geothermal gradients, deeper rock layers are usually hotter and very high temperatures whencombined with high overburden pressure change the rock properties from elastic to plastic
which as a result are much more difficult to drill through. This phenomenon was noticed by thescientists and engineers at the Kola Superdeep Borehole onshore location in Russia. It was
found that at a depth of 12,262 meters, the temperature encountered was about 180 °C. Hence,at these higher than expected temperatures (e.g. 180 °C vs 100 °C), deepening the borehole
was not technically feasible with the current state of drilling technology in 1989.
Table 1 provides an overview of mechanical properties for relatively hard rock belonging tosedimentary, metamorphic and igneous formations.
Table 1. Examples of Mechanical Properties for Hard Sedimentary, Metamorphic and Igneous Rocks

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2.6 Drilling Efficiency in Hard Rocks
Different indexes exist when trying to evaluate the efficiency of a drilling method but specificenergy is the most commonly used criterion. Specific energy is defined as the energy required
for removing a unit volume of rock. Specific energy is a function of the elastic and geotechnicalproperties of the rock but is also function of the bit type, design and drilling method parameters.

2.7 Hard Rock Drilling Industry Experience
Hard carbonate formations used to be drilled with rolling cutter technology and which wasrecently replaced by fixed cutter technology using PDC and diamond impregnated drill bits whentrying to drill carbonates with UCS up to 70 ksi. The change in bit type and design for theseapplications resulted in greater performance but there were still improvements that could be
made. Thus, the next step in drill bit performance was to conduct an R&D project aiming at
developing a new drill bit combining the durability of diamond impregnated bits with the drilling
efficiency of PDC bits. The outcome of this project provided a new bit design to drill hard rockcarbonate formations and has been replicated to drill harsh formations at several locations
around the world such as deepwater Canada (SPE 140353).

Figure 6. Hybrid PDC‐Impreg Bit Used to Drill Hard Carbonate Formation Deepwater Canada

Since the early 2000s, operators have launched several exploratory drilling campaigns offshore
Shetland islands. The challenges associated with the wells drilled in deepwater on the west sideof the islands are twofold: the harsh Metocean conditions and basalt layers having thicknesses
up to 820 ft and UCS that could be potentially be up to 30 ksi. Lab results directed service
companies’ effort towards the use of impregnated bits powered with Turbodrill to achieve high
ROP. After tested were conducted on basalt ranging between 26 ksi and 33 ksi, the 12-1/4” and8-1/2” drill bit that were designed used proprietary impregnated diamond inserts also called grit

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hot pressed inserts (GHI). In the original wellbore drilled, basalt sections with UCS up to 50 ksi
were encountered which created problems that led to sidetrack the well. On the sidetrack well,
the basalt was even thicker than anticipated (1,400 ft) and UCS reached up to 50 ksi
intermittently. Based on laboratory results discussed previously, an impreg bit associated with
Turbodrill enabled to drill the entire sequence in one single run (SPE 96575).

Figure 7. Impreg Bit for Drilling Basalt Offshore Shetland

The discovery of the Jubilee field offshore Ghana presented new challenges to the operators.
Not only located in a deepwater environment, the intervals to be drilled transitioned rapidly fromsoft shale to hard and abrasive sandstone with UCS that can peak at 25 ksi. Bit failures were
not uncommon and usually up to four trips were required to drill through a 1,300 ft section. The
main goal for a new bit design was to reduce bit trips by ideally completing the drilling of these
sections in one run. Therefore, ONYX premium cutters were integrated onto a PDC bit and athis optimized 12-1/4” PDC bit was the first to drill an entire section from shoe to TD in one
single run and enabled to save about two days of drilling time.

Figure 8. 12‐1/4” PDC MDSi816LBPX with ONYX Cutters

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2.8 Hard Rock Bit Selction Criteria
Bit performance is characterized by the interaction between the bit design and the associatedrock failure mechanism, type of rock being drilled, the bottom hole assembly (BHA) design, andthe drilling practices being used (i.e. weight on bit, rotational speed, hydraulics, etc…). If one
assumes that the optimum drilling practices are being utilized, then drilling efficiency becomes afunction of the following bit performance characteristics.
 Durability – defined as the bit’s ability to resist abrasive wear, teeth or cutter wear, bodyerosion, and thermal damage. Improving durability typically tends to reduce the bit’s
performance or rate of penetration.
 Stability – defined as the bit’s ability to either resist or initiate BHA initiated lateral,
torsional, and axial vibrations which can cause severe damage to the bit.
 Steerability – defined as the bit’s tendency to drill in the desired direction, or conversely,
the bit’s tendency to not “walk” or deviate the direction of the wellbore in an undesired
lateral direction, or cause an undesired deviation of the hole angle.
 Aggressivity – is defined as the rate of penetration (ROP) or how fast the bit drills basedon the bit’s response to an externally applied axial force, or the weight on bit (WOB).
Each of the parameters can be adjusted through modifications to the bit design. For example,
stability and durability in a PDC bit can be imp with the addition of more blades. Vibration can be
reduced by adjusting the number of cutters that are in contact with the formation at any one
time. However, maximizing the effectiveness of one parameter can adversely impact the otherparameters. For example, increasing the number of blades complicates the positioning of thenozzles which is critical for keeping the blades clean. Also, maximizing the bit’s durability willusually reduce its performance or ROP.
The parameters are therefore interdependent from the standpoint that changing one parameter
will impact the others sometimes unfavorably. The key to optimizing bit performance is the todetermine which parameter(s) is the most important to achieve the goals of the hole interval tobe drilled, and then to adjust the bit design to maximize that effectiveness of that parameter,while at the same time, minimizing the potential adverse effects on the other parameters.
As has been noted, the types of bits used to today to drill hard rock formations are roller cone
bits, diamond impregnated bit and PDC bits. Roller cone bits fail the rock through compression
and generally have good steerability and aggressivity. However, high bit weights are needed toovercome the high compressive strengths found in hard rock formations. High bit weights andthe rotation of the bit’s cones can severely limit the life of the bearings, cause brittle fracture of
the cutters and result in an overall decrease in durability.

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Diamond impregnated bits fail the rock by shearing a very fine layer of the formation which is
known as “plowing”, and generally have good steerability, durability and stability. However,
because only a fine layer of formation is cut at one time, these bits have a significantly lower
ROP than the other two types. These bits are typically run with high RPM down-hole turbines inorder to compensate for the low efficiency of the cutting elements and increase the ROP.
However the inclusion of a turbine in the BHA increases the risk of an unplanned trip in theevent of a failure of the turbine.
PDC bits fail the rock through shearing relatively large sections of the rock. This is the mostefficient method of mechanically failing rock because the shear strength of the rock is roughly
half of its compressive strength. However, PDC bits can have poor stability and be very
susceptible to brittle fracture under high loads as well as thermal fatigue at high temperaturewhen instability is present. In addition, their performance is sensitive to improper drilling
practices. Conversely, the very nature of these bits allows a great deal of flexibility for adjustingor modifying the performance characteristics parameters so that the above limitations can be
designed out of a particular PDC bit used for a particular application. With proper cutter
selection, cutting structure design, torque control component design, and hydraulic design, PDC
bits can provide the optimum balance between durability, stability, steerability and aggressivity
thereby maximizing bit performance. It can be argued that roller cone and diamond impregnatedbits need to be used only when a PDC cannot be properly designed.

2.9 Conclusions
To reach extreme depths in the Earth’s mantle with very hot and hard rocks, the use ordevelopment of an array of new technologies ranging from high electronics to new cuttermaterials will be required. However, as presented in this study, as drilling technology continues
to make significant progress, the challenges that are/were once considered to be difficult toovercome, have been resolved or are expected to be solved in the near future.

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3 Review of Hard Rock O&G Drilling Services
The main focus of Blade’s work for this project was to evaluate the hard rock drilling and coring
technology that currently exists within the oil and gas industry and to understand where and how
the technology will be trending in the future. To this end, Blade developed a presentation thatsummarized the BEAM project objectives and the technical issues around drilling and coring
into the mantle and met the four key oilfield service providers of bits and coring systems as well
as a major North American hard rock bit supplier. Initial meetings were held with each service
company to introduce the BEAM project, get information about their current product offerings
and their technical development efforts, and to identify their ability and willingness to provide
technical support to the BEAM project.
The meetings were quite informative and well attended by each company’s relevant product line
managers and technical representatives. These initial meetings were held with the following
service companies:-

National Oilwell Varco (NOV) who provides Reed and Hycalog bits-

Baker Hughes provides Hughes Christensen bits-

Halliburton who provides Security and DBS bits-

Schlumberger who provides Smith bits-

Ulterra who provides their own Ulterra bit product line

The key highlights from these meetings are as follows:•

All the companies were generally interested in the BEAM project, NOV and Ulterra inparticular.

•

Not surprisingly, each company also expressed concerns over "what's in it for me" to somedegree.

•All the companies believe that they have current products that would improve performanceby 30 to 50% compared to current scientific drilling practices and results.

•

All the companies have active ongoing technology development programs that will result in
new products on the market well before the nominal 2018 start date for the BEAM project.

•

All the companies have extensive experience with hard rock, and high temperature drillingand coring applications within the oil and gas industry – including basalt. This experience isillustrated in Figure 9 which shows Halliburton’s worldwide coring experience.

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Figure 9. Illustration of Halliburton’s Coring Experience•

All the companies have a sound technical understanding of drilling and coring mechanics aswell as the bit design and bottom hole assembly performance software models that are used
to develop optimized performance solutions based on predicted and/or actual field
operational data.

•

With the exception of Ulterra, all the companies have their own testing facilities and drilling
simulators that they use for bit and down-hole tool development under a variety of simulated
down-hole drilling conditions. NOV’s facility, for example, has the capability to simulate theoverburden pressure for different types of rock in atmospheric and pressurized conditions,and conducting downhole electronics testing with vibration at high temperatures. NOVpurchases large boulders of different rock types from mining operations around the world
and then uses them for bit development and performance testing. This includes examplesof sandstone, limestone, dolomite, granite and two types of basalt – one from the Faroe
Islands and one from the U.S. Pacific Northwest.

•

Only 30% of the bits used today are roller cone bits because of advances in PDC bit
technology. In addition it was noted that roller cone bits are generally the worst type of bit touse for coring. The weight on bit and the subsequent crushing effect of the bit teeth candamage the rock even before the core is cut which can adversely impact coring
performance and recovery.

•

Core recovery in the oil and gas industry today averages in excess of 90%.

•

Ulterra, based in Fort Worth, Texas is the 4th largest supplier of bits in North America. Theirmain focus is maximizing hard rock bit performance, and uniquely, 98% of their business isfrom rental bits. They also no longer provide roller cone bits because they have found that

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properly designed PDC bits work better in hard rock. Ulterra was the provider of the C-7
and C-9 core bits used by IODP, however in 2011 they sold this product line to a Russiancompany called Burintekh, which also has a manufacturing facility in Fort Worth.
•All of the companies offer standard bit product lines which are sufficient for most drilling
applications.
However, they can also provide customized bit designs for specificapplications. The use of customized bits to maximize performance is common practice in theoil and gas industry in areas of difficult or challenging drilling conditions. As such, all thecompanies recommended an iterative development process for identifying and/or
developing the optimum bit/core head solutions for the BEAM project. Ideally this would
involve testing a bit on an actual IODP hole, reviewing the bit condition and bit run
performance, making changes to the design and then running it again at a new IODP
location.

•

It is clear that a formal "R&D" program will not be required to address the BEAM project’s
technical issues around bit and coring performance because of these company’s current
experience and capabilities, and the natural progression of technology improvement within
the oil and gas industry.

A summary of the products and services that each of these service companies can provide isprovided in the following table.
Table 2 ‐ Service Company Capability Summary

BEAM is a complicated project from the standpoint of both the technical issues and the fact that
it is managed and will be operated by a non-profit scientific organization, which is obviously
atypical for the oil and gas industry. Several companies stated that they were unclear on how
best to move forward and requested that Blade prepare a list of possible steps that could betaken to address the BEAM project’s technical and commercial issues with the support of amanufacturing service company. Blade subsequently prepared this list and sent it to eachcompany. The intent was that the list could serve as the basis of internal discussions within thecompanies to help them determine their level of interest, resource requirements, costs and toserve as the basis for subsequent meetings with Blade. The questionnaire is provided inAppendix 1.

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In addition to this, Blade also met with IODP-USIO and obtained the morning reports anddrilling/coring performance results from the JOIDES Resolution operations during expeditions
309, 312, and 335 at the 1256D site off Costa Rica. Blade then collated and summarized thedata and sent it to each of the companies for review. The intent was to provide the companies
with actual IODP basalt drilling/coring data to review and comment upon.
In the end, only NOV and Ulterra responded to the questionnaire and only NOV reviewed the1256D drilling data. The lack of response from the other companies can be attributed to a lackof resources given their current business environment and the fact the BEAM project was notexpected to start until around 2018.
Of all the companies Blade talked to, NOV has by far expressed the most interest andenthusiasm about being involved in the BEAM project. NOV is a major oilfield service company
and has, over the past few years, bought numerous different companies, which has allowed
them to offer a wide variety of equipment and services to the oil and gas industry, from the mud
pumps on the Chikyu, to downhole tools, drilling fluids and bits. NOV stated that they are atechnology development company and feel that if they have the best technology, people will buy
their products and services. As such, they have less of a short term “what’s in it for me” attitude
than other service companies. They are genuinely interested in the BEAM project and quite
willing to help find solutions to the technical issues. In addition to providing ready access totechnical experts from their various product divisions, NOV also volunteered to run mechanicaltests on a core sample of basalt recovered from the 1256D hole to determine the rock’s
unconfined compressive strength (UCS) at no cost to IODP. NOV completed these tests inAugust 2012 and was able to compare these results to other types of basalt and other types of
hard rock that NOV has experience drilling. NOV is also interested in new technology andagreed to run tests on the nano-polycrystalline diamonds developed by Dr. Irifune of Ehime
University and compare them to the properties of the sintered diamonds NOV currently uses intheir bits. NOV is currently waiting on samples of the diamonds to begin testing which will also
be done at no cost to IODP. This is not to suggest that NOV will “always” be willing to do
everything for “free”, but a least for now at a foundational level, they have shown a willingness
to provide their own time and resources to help identify solutions to the technical issues aroundthe BEAM project.
The overall results of Blade’s investigations show that the major oil and gas industry bit andcoring service providers have extensive hard rock experience that includes drilling in basalt. In
addition, they currently offer products and services that would provide an improvement in bit andcoring performance compared to current scientific drilling practices and results. It is also
important to remember that drilling performance is more than just bit selection. Optimizing
performance involves a systems view approach that includes the bit, the bottom hole assemblyand drill string design, drilling parameters selection, drilling fluids system and so on. As such,these companies also have the technical expertise and support capabilities to develop custom
drilling systems solution to optimize drilling and coring performance. .

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4 Revised BEAM Operational Time Estimate
Based on the results of this study Blade was able to revise the mantle hole drilling time
estimates that were initially provided in Blade’s 2011 feasibility study to reflect what is possibleusing the technology currently available in the oil and gas industry. As described below, therevised time estimates are based around the results of the 1256D core testing done by NOV
and their own hard rock drilling experience.

4.1 Review of NOV 1256D Core Testing
As previously noted NOV ran mechanical tests on a core sample of basalt recovered from the
1256D hole to determine the rock’s unconfined compressive strength (UCS). IODP-MI provided
several core samples obtained from the bottom of the hole during Expedition 335 that was
conducted at the 1256D site in April 2011. NOV completed these tests in August 2012 and wasable to compare these results to other types of basalt and other types of hard rock that NOV has
experience drilling. The results of these tests are shown below and the full test report isprovided in Appendix 2.

Figure 10: NOV 1256D UCS Core Test Results Summary

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The average UCS for all 5 1256D tests is 30,728 psi. The first test resulted in a lower value thanothers which may have been due to pre-existing micro-fractures in the sample. If this result is
excluded, the average UCS of the reaming 4 tests is 34,034 psi. Note that basalts of the West
Faroes have UCS values ranging between 12 ksi and 45 ksi. Also, gneiss from the Dworshak
formation in Idaho has an average UCS value of 23.5 ksi and the John Day basalt located in
Oregon has UCS values ranging between 23.5 ksi and 53.5 ksi
From these results and NOV’s experience in drilling basalts and hard carbonate formations with
UCS values greater than 50,000 ksi, NOV provided the following estimates of drilling
penetration rates and bit life that would be ideally achievable for a mantle hole using a fixed
cutter PDC bit and a PDC bit run on a downhole motor.
Table 3: Estimated Ideal ROP’s Based on Current Technology

NOV further estimated that the coring penetration rates assumed in the 2011 feasibility study
could be improved by around 30%. It is assumed that the core test results reflect the hardnessof the rock in the “upper” part of the hole and that the rocks will progressively get harderresulting in a decrease in the ROP in the “lower” part of the hole. Note that these values arebroadly consistent with the statements made by the other service companies.

4.2 2011 Feasibility Study Operational Time Estimate Review
For reference, the following is a summary of the operational time estimates that were done
during the 2011 feasibility study. Recall that 4 different drilling/coring cases were examined foreach of the three candidate locations.
•

Case 1: Assumed that the hole is continuously cored to TD. This would be the ideal
situation as it would maximize the amount of scientific information obtained from thehole. It is also the most expensive.

•

Case 2: Assumed that long sections of continuous core are taken across the major
lithologic and geophysical transition intervals of key sections. For the time estimate it
was assumed that the upper third of each main stratigraphic interval was cored, themiddle third was drilled and the lower third was cored.

•

Case 3: Assumed that only spot coring is done during the last 10m of hole before each
bit trip.

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Case 4: Assumed that the hole is drilled to the Moho and that the mantle is cored. Thiswas done as a comparison to Case 1 since it represents the least expensive case.
Table 4: 2011 Feasibility Study Operational Time Estimates Summary

4.3 2012 Revised Operational Time Estimates
In order to account for the uncertainties that remain about the drilling conditions in a mantle holeand the fact that more detailed work on the bit designs will be needed, Blade has used ROP
values that are more conservative than the “ideal bit” values noted above. Despite this, therevised operational time estimates still demonstrate the significant improvement even relatively
modest increases in ROP can have on the overall operational time. The bit life estimatesprovided by NOV were still used because there is less uncertainty around the durability of
today’s bits than what the actual ROP might be. A comparison between the revised ROP’s
used for this project compared to the ones used for the 2011 feasibility study is shown below.
Table 5: 2012 Operational ROP’s

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The revised mantle operational time estimate was done for Cases 2 and 4 for the Hawaii
location since this location will require the most drilling/coring time. Cases 2 and 4 adequately
illustrate the philosophical differences between the amounts of time spent coring versus timespent drilling.
Revised Case 2 Results
Again this case is based on coring the upper third of stratigraphic section, drilling the middle
third, and then coring the bottom third of the major lithologic and geophysical transition intervals.
A summary of the revised operational time estimate for this case is shown below.
Table 6: Hawaii ‐ Case 2 – 2012 Revised Operational Time Estimate

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For comparison, the initial Case 2 time estimate from the 2011 feasibility study is shown below.
Note that the Total Core/Drill Days had been reduced from 688 to 460 days. This is a reductionof 228 days.
Table 7: Hawaii ‐ Case 2 ‐ 2011 Feasibility Study Operational Time Estimate

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A drilling curve showing the differences between the 2011 feasibility study and 2012 BEAM
project operational time estimates is shown below.

Figure 11: Case 2 ‐ 2011/2012 Drilling Curve Comparison

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Revised Case 4 Results
Again this case is based on drilling all the way to the Moho and then coring the mantle. A
summary of the revised operational time estimate for this case is shown below.
Table 8: Hawaii ‐ Case 4 ‐ 2012 Revised Operational Time Estimate

For comparison, the initial Case 4 time estimate from the 2011 feasibility study is shown below.
Note that the Total Core/Drill Days had been reduced from 422 to 224 days. This is a reductionof 198 days.

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Table 9: Hawaii ‐ Case 4 ‐ 2011 Feasibility Study Operational Time Estimate

A drilling curve showing the differences between the 2011 feasibility study and 2012 BEAM
project operational time estimates is shown below.

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Figure 12: Case 4 2011/2012 Drilling Curve Comparison

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5 Potential Issues with High Temperature and Down-hole Tools
5.1 Overview
High temperature drilling tools may see temperatures up to 150°C (300°F) for oil and gas
drilling, 250°C (500°F) for deep scientific drilling and 300°C (570°F) for geothermal drilling.
Drilling under such high temperature environments require that the tool and drilling equipment
down-hole can withstand these harsh conditions sometime over long period of drilling time. In
particular, there are many challenges associated with logging tools, sensors and motors whentrying to operate them.

Figure 13. High Pressure and High Temperature Tools (modified from SPE and Halliburton)

In general, there are two methods to handle very high temperature conditions. First, the drill
systems, tools, electronics and sensors have by design to withstand these temperatures. Thereis a significant research and development effort that is being carried on by the oilfield service
companies to study and create high temperature materials. The second method which comesfrom the geothermal industry is to circulate a pre-cooled drilling fluid in the borehole.
Unfortunately, as it was demonstrated in the 2011 mantle drilling initial feasibility study, becauseof the cooling effect of the 4,000 meters of seawater column, cooling the mud at surface will nothave an impact on the logging and drilling tools down-hole.

5.2 Estimated Down-hole Temperature
Figure 14 below is a revised version of the chart plotting the assumed down-hole temperature
profiles for three candidate locations that can be found in the 2011 mantle drilling initial

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feasibility study report. The maximum bottom-hole temperature (BHT) estimates are based uponprevious models of formation burial depth and age provided by scientists from the IODP. Also,
note that these temperature profiles have taken into account the cooling effect of the 4,000
meters of seawater with an average temperature at seafloor of about 2-4°C and a few available
temperature measurements made during operations at the 1256D hole. As a result, theuncertainties in these BHT estimates are believed to be ±50°C. It is of interest to notice that the
BHT at Hawaii is expected to be about 150°C while the estimated BHT at Baja California and
Hawaii is about 250°C.

Figure 14. Estimated Bottom-hole Temperature for Three Candidate Locations

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5.3 Review of Current O&G Industry Capabilities
5.3.1 Summary of Service Company Meetings
1. A meeting with Smith was arranged for August 8. The meeting was essentially focused onreviewing Smith’s drilling current state of the art and their latest development regarding hightemperature drilling and logging tools.
The key outcomes from the meeting are as follows:•

In 2010, “only” 9% of total footage drilled was for BHT ranged between 300°F and
350°F.

•

Their engineers are however focusing on developing tools with higher operating
temperatures is response to industry trends towards drilling in higher temperatureenvironments.

•

The challenges are for high temperature resistance of elastomers, electronics andsensors.

•

Currently testing 200°C tools but it is still a niche market.

2. A meeting with Weatherford was arranged for August 10. The meeting was mainly focusedon reviewing Weatherford’s drilling current state of the art and their latest development
regarding high temperature logging tools. Note that Weatherford embarked upon thedevelopment logging tools and decided to focus on the HPHT niche market.
The key outcomes from the meeting are as follows:•

Weatherford current offering is divided between standard pressure and temperature
tools (i.e. up to 150°C and 20,000 psi) and high temperature pressure and temperature
tools (i.e. up to 180°C and 30,000 psi) as presented in Table 10 and Table 11.

•

New tools are being developed for temperature as high as 190°C and will be soon field
tested in Thailand.

•

Engineers are also working on signal transmission issues when drilling very deep wells.

Advances in LWD and MWD tools have been significant over the last decade and the next
3-4 years are expected to be a “different world”. However, the biggest challenges remain
when trying to drill formations with BHT of 250°C and above. Indeed, the memory chips
have to survive a moisturizing environment with high vibrations which is one of the criticalparameters data transmissions in the borehole. Also, note that every 10°C in temperature
increase, the life of the component on the LWD and MWD tools are reduced by about 50%.
3. A meeting with Halliburton was arranged for August 24. The meeting was focused on a
general discussion regarding Halliburton’s high temperature drilling capabilities.

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The key outcomes from the meeting are as follows:•

Halliburton vertical drilling tool is rated for temperature up to 250°C and has recently
been used in a packed drilling assembly in Thailand (i.e. BHT = 250°C).

•

Engineers are currently working on MWD tools rated for 230°C for a single run or 215°C
for multiple/longer runs. LWD tools are rated for about 200°C.

•

Halliburton is currently developing an active cooling technology that has been tested in
the lab that may deliver up to 100°C temperature reduction for the circulating conditions.

Tables 11-13 below respectively summarize the available down-hole tools for standard
temperature and pressure tools, high temperature / high pressure and extremely hightemperature / extremely high pressure tools, ultra high temperature and pressure tools currently
under development or that are being field tested.

5.3.2 Standard Temperature Tools
Table 10 presents the current Weatherford and Halliburton tools available to drill and evaluate
formation with pressures up to 20,000 psi and temperatures up to 300°F (150°C). Note that
there are currently four tool sizes available ranging between 9-1/2” and 4-3/4” and that
azimuthal gamma ray, azimuthal density, neutron porosity and formation pressure tester are notavailable with 9-1/2” tool size.

5.3.3 High Temperature Tools
Table 11 lists the current Weatherford and Halliburton tools available to drill and evaluate highpressure and high temperature formations with maximum pressure rating equal to 30,000 psi
maximum temperature rating equal to 350°F (180°C).

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Table 10. Standard Pressure / Temperature Down-hole Tool Ratings

Table 11. High Pressure / Temperature Down-hole Tool Ratings

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Note that there are also currently four tool sizes available to drill and evaluate high pressure andhigh temperature formations, again, ranging between 9-1/2” and 4-3/4” and that, similarly tostandard tools, azimuthal gamma ray, azimuthal density, neutron porosity and formationpressure tester are not available with 9-1/2” tool size.

5.3.4 Developmental Effort / Trends
Table 12 provides the ongoing state of R&D at Weatherford and Halliburton laboratories for
extreme and ultra-high pressure and temperature tools. Ultra-high tools are currently being
designed and developed to drill and evaluate high pressure and very high temperatureformations with maximum pressure rating equal to 30,000 psi maximum temperature rating
equal to 390°F - 440°F (200°C - 230°C).
In addition, it is important to note that there are “only” two tool sizes that will first be available todrill and evaluate high pressure and very high temperature formations: 4-3/4” and 6-3/4”. Also,
azimuthal gamma ray, sonic and formation pressure tester will not be available for any of thetool sizes in the next couple of years.
Table 12. Current High Temperature Down-hole Tool Development

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5.3.5 Discussion
As shown in Figure 14, except for the Hawaii location where BHT are estimated to be around
300°F (150°C), the other two locations have deep boreholes with temperatures that are
expected to be as high as 480°F (250°C). Thus, these down-hole static temperatures and eventhe down-hole circulating temperatures (i.e. chilling the drilling fluid does not help in ultradeepwater drilling) exceed the temperature ratings of most of the down-hole tools that arecommercially available (i.e. see Tables 11-13). Although, at the rate of improvement in downhole component temperature rating and using innovative cooling technology such as the one
currently developed by Halliburton, the next 3-4 years may see a next generation in LWD and
MWD tools that may be capable of drilling and evaluation formations with temperature as highas 250°C. Again, as previously mentioned in the conclusions of the 2011 mantle drilling initial
feasibility study report, down-hole tools are already available if the BHT does not exceed 350°F(180°C) such as the borehole that could be drilled at the Hawaii location.

5.4 Marine Drilling Riser
5.4.1 Summary of Service Company Meetings
1. A meeting with JFE was arranged for July 25. The meeting specifically focused on the latest
development in material science regarding high strength steel marine drilling risers.
The key observations from the meeting are as follows:•

X-100 material line pipe is now available to manufacture the drilling riser main tube.

•

The first collaboration will be with NOV high strength manufacturing of drilling riser group

The impact of this technical improvement could be significant on the design and application
for ultra-deepwater steel marine drilling risers. Not only an 100 ksi yield material will enablea thinner wall (i.e. weight reduction per riser joint) in order to achieve the same performancefor a given field application, but also will allow more allowable stress for the riser main tube.
As a result, a thinner walled drilling riser would allow deploying greater lengths of riser joints
for the same floating drilling structure tensioning system. Note also that the maximum VME
in the drilling riser tube cannot exceed 67% of the minimum yield strength. Thus, 100 ksi
material would enable higher stresses in the riser tube which imply that either higher mud
weight could be used or greater water depths could be drilled through.
2. A meeting with RTI International Metals was arranged for August 2. The meeting discussion
emphasized on the current state of art and recent field application for titanium risers andmore specifically titanium drilling risers.
The key observations and outcomes from the meeting are as follows:•

RTI has recently designed, manufactured and field deployed an entire titanium marine
drilling riser. However, this was done for a well located in relatively shallow waters and

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BEAM Project – High Impact Systems, Technical Review and Risk Reduction Studyso far no titanium drilling riser has been either deigned or manufactured by RTI for a
deepwater well.
•

2 grades of titanium: ASTM 23 and ASTM 29 would be readily suitable for deepwatertitanium drilling risers.

Because of the drastic weight reduction associated with titanium (i.e. 40% lighter than steel)and much higher yield strength (i.e. 120-130 ksi), titanium drilling risers could be used forweight reduction for the entire drilling riser (i.e. main tube and/or auxiliary lines). Thus,
similarly to 100 ksi steel, titanium drilling risers could be used to drill through ultra-deepwater
depths that have never been reached before with steel material and also utilized for harshenvironments with high pressure reservoirs (high mud weight). The additional benefit istitanium high resistance to fatigue damage which could be used for high current
environment and very long drilling campaign such as the one planned for the mantle drillingwell. Obviously, the main disadvantage of titanium products is their relative high prices incomparison to steel.
3. Three meetings with Alcoa Oil & Gas were arranged for August 9, August 22 andSeptember 12. The meeting discussions were principally focused on the current state of art
and recent field applications for aluminum drilling risers.
The key observations and outcomes from the meetings are as follows:•

Alcoa has been designing, manufacturing and providing full aluminum marine drillingrisers for 4 Noble drilling rigs. Note that the initial use of aluminum drilling riser withNoble fleet was to extend the water reach of existing 3rd and 4th generation floaters built
in the 1980s and that these rigs have operated offshore Brazil.

•

Independently from Blade analysis and suggestions in the 2011 mantle drilling initial
feasibility study, Alcoa has recently marketed the concept of hybrid drilling riser with theriser main tube, the hydraulic and booster lines made of steel but with the choke and killlines made of aluminum. Note that, usually, the total weight of auxiliary lines or only
choke and kill lines accounts for respectively 40-50% and 20-30% of the total weight ofan entire drilling riser.

Because of the large weight reduction associated with aluminum material (i.e. 60% lighter
than steel) but generally lower yield strength (i.e. 40-60 ksi), aluminum drilling risers could
be used for weight reduction for the entire drilling riser (i.e. main tube and/or auxiliary lines)
but would be better suited for auxiliary lines keeping the riser main tube with a high yieldstrength material (X-80, X-100 or titanium); hence, illustrating the concept of hybrid drillingrisers. Thus, aluminum drilling risers could be used to drill through ultra-deepwater depths
with existing floaters. However, significant work and studies remain to be done to investigate
the potential corrosion issues that are associated with using aluminum in seawater (i.e.
chloride content), the eventual offshore application for high strength aluminum alloys suchas alloys 1980, 1953, C22n, C99N and C92N, the load sharing capability of aluminum riser

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main tube and auxiliary lines, the fatigue behavior of aluminum joints and the welding
process for 75-foot and 90-foot long riser tubes.
4. A meeting with GE Oil & Gas (a division of General Electric Company) was arranged forAugust 7. The meeting discussion was also focused on the current state of art and recent
field applications for GE high strength drilling risers for deepwater applications.
The key observations and outcomes from the meetings are as follows:•

GE Oil & Gas has designed, manufactured and implemented in deepwater regions
several high strength (i.e. X-80) steel marine drilling risers.

•

The current high-end drilling riser product is an “H-Class” (i.e. 3.5 million pounds tension
rated). Note that the best class in the industry is currently “I-Class” (i.e. 4.0 million
pounds tension rated) which is what is onboard the Chikyu drill-ship.

•

GE Oil & Gas is currently other advanced material such as aluminum, titanium and evencomposite tubes for drilling riser applications.

5. A meeting with NOV was arranged for August 20. The meeting discussion was first
dedicated to the current state of art and recent field applications of NOV high strength
drilling risers. In addition, a tour of the entire NOV manufacturing plant has been provided toBlade Energy where the manufacturing process of BOP/LMRP, riser joints and special
drilling riser components has been witnessed.
The key observations and outcomes from the meetings are as follows:•

NOV designs, manufactures and sells a wide range of drilling riser product ranging from
“C-Class” (i.e. 1.0 million pounds tension rated) to “I-Class” (i.e. 4.0 million pounds
tension rated).

•

NOV also manufactures all the special drilling riser component for deepwater drilling (i.e.
telescopic joint, tension ring, termination joint, keel joint, pup joint, riser fill-up valve, riser
adapter, riser running tool, riser spider and gimbal).

•R&D development of high strength steel drilling risers that will be able to operate in
12,000 feet of water and using 16.0 to 18.0 ppg mud weights.

•

When trying to drill through water depths greater than 12,000 feet, both new riser design
and materials are going to be needed to overcome all the issues associated with weightand strength.

6. A meeting with Cameron was arranged for August 30. The meeting discussion was centeredon the current state of art and recent field applications of Cameron high strength drillingrisers.
The key observations and outcomes from the meetings are as follows:

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Cameron has been the first service company to design, manufacture and sell an “IClass” (i.e. 4.0 million pounds tension rated) marine drilling riser which was specificallydesigned and purchased by JAMSTEC. So far, this high class drilling riser has only beensold to JAMSTEC and still constitutes the best high strength marine drilling riser that
Cameron has in its catalogue.

•

In the near future, Cameron may produce a “J-Class” that would be rated for 4.5 or 5.0
million pounds tension rating.

•

Cameron was part of a Joint Venture with Alcoa Oil & Gas to investigate the next
generation of ultra-deepwater riser systems. Note that this JV was stopped in 2011.

•

Cameron is actively working on 20,000 psi riser systems. The current state of the art in
the deepwater industry is to use 15,000 psi to drill to oil and gas reservoirs. As a result,designing a 20,000 psi drilling riser demands that the wall thickness of the choke and killline tubes will be greater; thus the riser joints will be heavier.

7. A meeting with Aker Solutions was also arranged for August 30. The meeting discussion
was centered on the current state of art and recent field applications of Aker’s high strength
drilling risers.
The key observations and outcomes from the meetings are as follows:•

Aker Solutions has designed, manufactured and field deployed a slightly different ofdrilling risers called CLIP which are equivalent to “H-Class” (i.e. 3.5 million pounds
tension rated) and that can theoretically function in about 12,000 feet of water. However,this water depths are expected to be reachable using a “non-load sharing” design (i.e.
tensile load is supported just by the riser main tube) and “only” 12.0 ppg drilling fluid.

•

Aker Solutions is currently in the process of designing and manufacturing and “I-Class”(i.e. 4.0 million pounds tension rated) CLIP drilling riser that could be deployed in about
12,500 feet of water with “load sharing” capacity (tensile load is supported both by theriser main tube and the auxiliary lines) and that could handle drilling fluids up to 16.0
ppg. This new drilling riser joint should be available to market by 2014.

•

Aker Solutions is also currently investigating hybrid risers using composite materials (i.e.
carbon fiber) that would be a coating layer on a thin matrix made of high strength steel.

8. A meeting with Balmoral was scheduled for July 26. The meeting discussion was centeredon the current state of art and recent field applications of Balmoral buoyancy systems that
equipped bare drilling riser joints.
The key observations and outcomes from the meetings are as follows:•

Balmoral has already designed, manufactured and field tested buoyancy systems to fit
ultra-deepwater drilling riser joints with their high-end product being already capable ofequipping riser joints in up to 15,000 feet of water.

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9. A meeting with Trelleborg was scheduled for August 7. The meeting discussion was firstcentered on the current state of art and recent field applications of Trelleborg buoyancy
systems that can equip bare drilling riser joints and then a tour of Trelleborg manufacturing
plant was given to Blade Energy.
The key observations and outcomes from the meetings are as follows:•

Trelleborg has already designed, manufactured and field tested buoyancy systems to fit
ultra-deepwater drilling riser joints with their high-end product being already capable ofequipping riser joints in up to 12,000 feet of water.

•

Trelleborg has already designed and manufactured buoyancy systems for other marine
components that have been deployed on ROV’s in water depths up to 30,000 feet.

5.4.2 Discussion
High strength steel (i.e. 80 ksi) is currently the most widely used material for deepwater drillingand drilling riser systems. However, when drilling with a marine drilling riser in water depths
averaging 10,000 feet with relatively high drilling fluids (i.e. 16.0-18.0 ppg), the technical limit ofexisting high strength riser systems commonly manufactured with 80 ksi steel material for theriser tube, auxiliary lines and connectors is reached.
Hence, as water depth increase beyond 10,000 feet and the true vertical depth of borehole
below the mudline increase beyond 15,000-20,000 feet, the external pressure due to seawaterand the internal pressure due to the mud weight required to balance the deep formationpressure that are acting on the marine drilling riser may become too large and; therefore will
require that stronger materials such as X-100 steel, titanium or composite may be used. Also,
since stronger drilling risers will often produce heavier risers (i.e. because of the increase in themain tube wall thickness), aluminum may also be considered as an alternative to be used forthe design of auxiliary lines such as hydraulic, booster, choke and kill lines and thus reduce theoverall weight of the drilling riser.
Nevertheless, even though both aluminum and titanium drilling risers have been already beendeveloped and tested, they have rarely been applied but still are showing great potential.
Moreover, as of today, composite materials have still not been tested or field deployed for
deepwater drilling riser but has already had success for smaller diameter (i.e. 5.0 to 8.0 inches)
production risers in the North Sea. Thus, as investigated by Aker Solutions and GE Oil & Gas, isbelieved that, at least, for auxiliary lines, and because of high strength and weight saving
associated with carbon fiber or carbon epoxy, composite materials may be a cost-effective
solution for ultra-deepwater marine drilling riser systems.

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5.4.3 Riser Options Review
Tables 13 and 14 illustrate respectively the material properties and multiple possible
configurations that can be used to design and manufacture a marine drilling riser for ultradeepwater applications (i.e. water depth greater than 12,000 feet).
Table 13 list four materials that have already been used for riser systems in the oil and gas
industry. High strength steel (i.e. 80 ksi) is currently the most widely employed material to
manufacture deepwater drilling riser systems. Also, newly available 100 ksi steel materials
constitute a near term easy solution to upgrade and increase the ultra-deepwater reach ofdrilling riser systems. Then, aluminum and titanium drilling risers have been developed, tested,rarely applied though but have shown great potential for greater water depths (i.e. 10,000 –
15,000 feet) because of the drastic weight saving. Finally, even though composite materials
have not been tested and field deployed for deepwater drilling riser, they may, in combination
with high strength steel represent a good alternative to titanium or aluminum products.
Table 13. Materials for Marine Drilling Risers

Table 14 presents nine different configurations that may be used for drilling riser system design.
Table 14. Nine Possible Configurations for Drilling Risers to Reach Ultra-Deepwater

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5.4.4 Pro’s and Con’s Comparison
Table 16 lists the advantages and drawbacks of all the riser options that are either currently
available to the ultra-deepwater drilling industry or at a conceptual stage development within
service companies or material science department in universities.
Table 15. Advantages and Drawbacks for the Nine Drilling Riser Options

5.5 Review of Survey Services
5.5.1 Metocean Survey
1. A meeting with RPS Evans-Hamilton was scheduled for August 21. The meeting discussion
was essentially centered on the current state of art and recent field applications of RPS
services regarding Metocean survey for deepwater environments. In addition, a tour of RPS
facility where current measurements devices are stored has been provided to Blade Energy.
The key outcomes from the meetings are as follows:

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BEAM Project – High Impact Systems, Technical Review and Risk Reduction Study•

RPS provides worldwide services for field measurements of currents, waves andmeteorological conditions. Survey of a full water column may take about 12 months andcost about $750,000.

•

RPS also provides services for modeling of oceanic currents, winds and waves as wellas hindcasting and forecasting for a given offshore location.

There is no technical depth limitation (i.e. up to 20,000 feet) associated with probes, sensors
and instruments that can measure oceanic currents and wave conditions. RPS has alreadytaken measurements off the islands of Hawaii and recognized that publicly available fordeepwater measurements for Cocos plate, Baja California and Hawaii are scarce as
opposed to coastal data which are more easily available especially within the local
universities. Therefore, a desktop study (i.e. $25,000 per site) will usually be the first step totake in trying to identify the best location in order to conduct drilling operations for about 1
year.
2. A meeting with Fugro Geos was scheduled for August 23. The meeting discussion was also
focused on the current state of art and recent field applications of Fugro Geos services
regarding Metocean survey for deepwater environments.
The key outcomes from the meetings are as follows:•

Fugro Geos provides worldwide services for field measurements of currents, waves andmeteorological conditions. Survey of a full water column usually takes at least 1 full year
(i.e. 8 weeks lead time for field deployment + 1 year of measurement + 4 weeks of data
quality control + 4 weeks for data processing and results) and costs about $1,000,000.

•

Fugro Geos also provides services for modeling of oceanic currents, winds and waves
as well as hindcasting and forecasting for a given offshore location. In addition, marine
growth analysis which is very important for drilling riser design when staying on location
for several months can be calculated 3-4 months after the buoys have been deployed.
However, note that forecast modeling for current is not as advanced as weathermodeling. Thus, wave forecasting can be done for period of time up to 30 years using inhouse advanced models even though no wave data are taken as the exact offshore
location. Nevertheless, survey will still constitute the best solution to determine an
accurate weather window and therefore the drilling rig operability assessment.

•

From Fugro’s experience, it seems like Cocos plate will have high oceanic currents
where Hawaii Metocean conditions will be more benign except during the winter season
that sees a high wave energy environments. In addition, Baja California may have themost benign weather conditions but has the deepest waters and is potentially exposed tonumerous hurricanes.

Similar services such as a desktop study (i.e. $20,000 per site) are also recommended by
Fugro Geos trying to identify the best location in order to conduct drilling operations forabout 1 year.

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5.5.2 Geohazards Survey
1. A second meeting with Fugro Geos was scheduled for August 23. The meeting discussion
was centered on the current state of art and recent field applications of Fugro Geos services
regarding geohazard surveys near the borehole site for deepwater environments.
The key outcomes from the meetings are as follows:
Fugro Geos provides worldwide services for geohazard surveys using 3D seismic andspecialized high resolution 3D seismic for the shallower layers. In addition to the 3D seismic,
multi-beam bathymetry are used to collect high resolution images of the seafloor to assess
slope stability and potential faulting. Note that multi-beam bathymetry may also be used toestimate the sediments strength where the structural casing of the scientific borehole will beset. A general cost estimation for 3D survey + multi-beam bathymetry and geotechnicalborings is about $5,000,000. However, significant lead time (i.e. 1 year) must be accounted
for before these geohazard surveys can start.

5.6 Expandable Casing
The hole problems that occurred on IODP expedition 335 at the 1256D site off Costa Rica in
April 2011 would tend to suggest that the base case well design assumed in Blade’s 2011
feasibility study (reference Appendix 3) is likely optimistic and that more casing could be
required in the event of unexpected downhole problems. The use of expandable casing may be
a way to preserve hole sizes by allowing the length of an existing casing string to be effectively
extended, or to isolate specific problem zones. Expandable casing has been used in the oil andgas industry since late 1999 to mitigate the impact of unexpected hole problems.
New developments in expandables have improved the reliability, and increased the applicable
uses of this technology. For example, large diameter tubulars are being developed for
applications higher in the wellbore, offering more flexible use of the expandable tubulars.
Expandables are now being developed from 3.5” to 20” OD’s. The three major companies
currently providing this technology are Baker Hughes, Weatherford, and Enventure.
The expansion process has varied over time, and varies by company. The most prevalentapproach is to drill, run the expandable, condition mud, and cement as usual. The cemented
liner varies from the typical sense in that there is an expansion cone located at the bottom of theliner in the launcher. A plug is pumped down-hole past the cone, latched, and expansion is theninitiated. The volume below the cone, within the liner, and sealed by the plug is pressurized. The
pressure drives the cone upward, expanding the pipe. The cone is also pulled axially; thissteadies the process, enables extra force to be applied in case of a stuck cone, and allows
mechanical expansion if pressure is lost due to liner splitting or connection failure.
The following figure illustrates the potential benefits of using expandables. The planned casing
program for a deepwater well is shown on the left side of the figure. The right side of the figure

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BEAM Project – High Impact Systems, Technical Review and Risk Reduction Studyshows how an additional contingency liner can be incorporated into the well design without
requiring a small diameter string to be run at the 16.150” casing point as would be typically be
the case.

Figure 15: Expandable Casing Example

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6 Conclusions and Recommendations
The key conclusions and recommendations from this study are as follows.
•

The major bit and coring system service providers have a great deal of experience withdifficult hard rock drilling environments in the oil and gas industry. They currently all haveproducts that could improve current IODP drilling performance. Perhaps more importantly,
they all have the design, testing, manufacturing, analysis, and technical support capabilities
needed to develop optimized solutions for difficult drilling conditions.

•

At this point it is not practical to recommend a specific bit type or coring system for a mantle
hole mainly because optimizing performance is more than just selecting a bit. Optimizing
performance requires a systems level approach that considers bit design, drill stringmechanics, bottom hole assembly and drill string design, hydraulics, drilling fluids and so on.
In addition, there are a variety of potentially viable options that need to be considered that,for example, range from conventional drilling, to using a bit and a downhole motor, to using
a diamond impreg bit and a downhole turbine and so on.

•

Achieving success on a mantle hole will involve more than just selecting a promising looking
bit and running it. Blade believes that IODP should partner with 1 or 2 of these service
companies in order to take advantage of the full range of experience and services they canprovide during both the planning and operational phases of the project. Blade further
recommends that NOV be one the companies because they have the most familiarity andunderstanding of the technical issues and have expressed the most interest in the project.

•

As illustrated in Section 4, working closely with a service company to develop an optimized
solution to the mantle hole challenges can significantly reduce both the operational time andrisk associated with the project.

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7 Main References
American Petroleum Institute (1993) RP 16Q/ISO 13624-1, Recommended Practice for Design,
Selection, Operation and Maintenance of Marine Drilling Riser Systems.
Bar-Cohen Y. and Zacny K. 2009. Drilling in Extreme Environments – Penetration and Samplingon Earth and other Planets. WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim.
Bourgoyne Jr AT, Millheim KK, Chenevert ME & Young Jr FS (1991) Applied Drilling
Engineering, Society of Petroleum Engineers, ISBN:978-1-55563-001-0.
Center for Deep Earth Exploration, Japan Agency for Marine Earth Science and Technology,
Kanazawa, Yokohama, Japan, Vol1 –Vol10.
Center for Deep Earth Exploration, Japan Agency for Marine Earth Science and Technology,
Kanazawa, Yokohama, Japan, Chikyu Drilling Equipment and Systems, 2008.
Det Norske Veritas. Offshore Service Specification. DNV-OSS-302. Offshore Riser Systems.
October 2010.
Det Norske Veritas. Recommended Practice. DNV-RP-F201. Design of Titanium Risers.
October 2002.
Expedition 309/312 Scientists, 2006. Expedition 309/312 summary. Teagle, D.A.H., Alt, J.C.,
Umino, S., Miyashita, S., Banerjee, N.R., Wilson, D.S., and the Expedition 309/312 Scientists.
Proc.IODP, 309/312: Washington, DC (Integrated Ocean Drilling Program Management
International, Inc.), 1–127. doi:10.2204/ iodp.proc.309312.101.2006.
Expedition 309/312 Scientists, 2006. Site 1256. In Teagle, D.A.H., Alt, J.C., Umino, S.,
Miyashita, S., Banerjee, N.R., Wilson, D.S., and the Expedition 309/312 Scientists. Proc. IODP,
309/312: Washington, DC (Integrated Ocean Drilling Program Management International, Inc.),
1–549. doi:10.2204/iodp.proc.309312.103.2006.
Ildefonse, B. et al. 2010. The MoHole A Crustal Journey and Mantle Quest. Workshop Report.
Kanazwa, Japan, 3-5 June 2010.
IODP. Mission Moho – Formation and Evolution of Oceanic Lithosphere, Full Report. Sept 7-9,
2006, Portland, Oregon, USA. An international workshop sponsored by IODP-MI.
Neo, N., Yamazaki, S., and Miyashita, S., 2009. Data report: bulk rock compositions of samples
from the IODP Expedition 309/312 sample pool, ODP Hole 1256D. In Teagle, D.A.H., Alt, J.C.,
Umino, S., Miyashita, S., Banerjee, N.R., Wilson, D.S., and the Expedition 309/312 Scientists,
Proc. IODP, 309/312: Washington, DC (Integrated Ocean Drilling Program Management
International, Inc.).

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Ochoa, O. Composite Riser Experience and Design Guidance. Final Project Report Prepared
for the Minerals Management Service. October 2006.
Persent et al. New Riser Design and Technologies for Greater Water Depth and Deeper Drilling
Operations. SPE Paper 119519 presented at IADC/SPE Drilling Technology Conference andExhibition, Amsterdam, The Netherlands, 17-19 March, 2009.
Skinner et al. 2010. Coring at Extreme Temperatures, Design and Operation of a Core Barrel for
the Iceland Deep Drilling Project (IDDP). Proceedings World Geothermal Congress, Bali,
Indonesia, 25-29 April 2010.
Teagle, D.A.H., and Wilson, D.S., 2007. Leg 206 synthesis: initiation of drilling an intact sectionof upper oceanic crust formed at a superfast spreading rate at Site 1256 in the easternequatorial Pacific. In Teagle, D.A.H., Wilson, D.S., Acton, G.D., and Vanko, D.A. (Eds.), Proc.
ODP, Sci. Results, 206: College Station, TX (Ocean Drilling Program), 1–15.
doi:10.2973/odp.proc.sr.206.001.2007.
Traeger, R. K. Borehole Measurements in Extreme Environments. 26th US Symposium on RockMechanics, Rapid City, SD, 26-28 June 1985.

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Appendix 1: BEAM Follow-up Questionnaire (generic)
BEAM - Borehole into Earth’s Mantle
Bit and Coring Technology Development Questions
BEAM is a complicated project from the standpoint of the technical issues and the fact that it ismanaged and will be operated by a non-profit scientific organization. As such, it is presently
unclear how best to move forward to resolve the technical issues. To facilitate a discussion
about this, Blade has prepared a list of possible steps that could be taken to address thetechnical and commercial issues with the support of a manufacturing service company. The
idea is that the list could serve as the basis of internal discussions within <company> to help
determine your level of interest, resource requirements, costs and so on.
Blade would therefore appreciate it if <company> could review the steps provided below andindicate your level of interest. We would not expect a lengthy formal response but would be
happy to meet with you to discuss this in more detail at your convenience.
Again, Blade has been asked by IODP to:•

Identify current hard rock drill bit equipment and services.

•

Investigate potential technological gaps and improvements that will enable hard rock drill
bits to stay on-bottom longer, decreasing drilling time and risk.

•

Identify current hard rock coring systems and services.

•

Investigate possible development of new hard rock coring systems to improve the quality
and quantity of cores recovered in order to satisfy the scientific objectives.

•

Provide a recommendation of the most efficient and most viable hard rock drill bits andcoring systems for the BEAM drilling project spud date in 2017-2018.

•

Provide an estimate of how the designers, manufacturers, and service companies ofsuch equipment and services may accelerate their technological offerings, including an
estimate of the technological improvement costs to IODP and the scientific drilling
community.

•

Identify additional high-impact drilling equipment and services for the BEAM project
where technological improvements will also reduce project time and risks.

Possible Technical Issue Resolution Steps
1. Would you be willing to provide information / marketing material on your current hard rock bit
product lines that might be suitable for the BEAM project?
2. Would you be willing to provide information / marketing material on your current hard rockcoring system product lines that might be suitable for the BEAM project?

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3. Would you be willing to provide information on hard rock bit designs and coring systems thatare under development that might be suitable for the BEAM project?
4. Would you be willing to provide information on the key design features for high temperature,
hard rock roller cone, fixed cutter, and impreg bits and core systems? For example, what do
you think the main issues are, what are the ideal design features that one would look for,which ones have current solutions, which might need an R&D program to address the
BEAM project needs?
5. What kind of modeling software do you have that, for example, considers lithology and rockstrength for the selection of optimum bits? Will you provide an input list or form, so that wecan begin gathering sufficient information?
6. What bit testing facilities do you have and what kind of drilling related variables can be
adjusted?
7. Would you be willing to provide information on your previous experience drilling and coringin high temperature and hard rock areas that are similar to what is expected in the BEAM
project. What information would you need from Blade/IODP to make this comparison?
8. Would you be willing to review previous IODP project bit and coring performance records
and provide a cursory evaluation of the date, your general opinions of the results andgeneral suggestions for alternative bits and core heads – at no cost?
9. Would you be able and willing to do a detailed examination of previous IODP project bit andcoring performance records and well log data and do a comprehensive performance
evaluation in order to come up with a optimized bit and core/head recommendation basedon your current product line offerings? If so, how much would it cost and how long would it
take, and how would it need to be structured?
10. Would you be willing to participate in an R&D program to address the bit and coring
technical issues associated with the BEAM project? How would you think a program likethis should be structured and roughly what would it cost?
11. Do you have any other opinions, suggestions or advice?
Blade Energy Partners
May 2012

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Appendix 2: 1256D Core Test Report
Embedded below is the report on the UCS core testing that was done by NOV.

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Appendix 3: Base Case Well Configuration
For reference, below is the base case well design configuration that was assumed during
Blade’s 2011 feasibility study.

Figure 16: Base Case Mantle Well Configuration

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Appendix 4: Glossary of Terms
BHA – Bottom Hole Assembly
The lower portion of the drill string below the drill pipe consisting of, at minimum, the bit andheavy drill collars. The BHA provides the force for the bit to overcome the strength of the rockthrough the application of weight applied to the bit provided by the drill collars. The BHA can be
configured in many different ways to facilitate building or dropping the angle of the wellbore fordirectional wells or to keep the wellbore straight in a vertical well. Specialty tools (LWD, MWD)
are frequently incorporated into the BHA to provide various down hole measurements offormation properties and/or drilling parameters. The diameter of the tools that make up the BHA
will vary depending on the hole size that is being drilled. Some common bit and BHA size
combinations are shown below.

BOP – Blowout Preventer
A large, specialized mechanical valve installed at the top of a well that is to used to seal, control
and monitor the down hole formation pressures in oil and gas wells. Individual BOP’s are
installed redundantly in stacks to form the overall BOP Stack. BOPs come in a variety of styles,
sizes and pressure ratings. Some can effectively close over an open wellbore, some aredesigned to seal around tubular components in the well (drillpipe, casing or tubing) and others
are fitted with hardened steel shearing surfaces that can cut through the tubular components.
LMRP – Lower Marine Riser Package
Connects the marine drilling riser to the subsea BOP stack located at the seabed on top of the
wellbore. The LMRP provides the means to disconnect from the well in the event of severe
weather or during an emergency abandonment so that the marine drilling riser can be pulled tothe surface leaving the well safely shut in with the subsea BOP stack. The LMRP consists of a
BOP connector, an annular type BOP and a flex joint assembly which permits the riser a degreeof lateral movement while it is suspended in the water column.
LWD – Logging While Drilling
The real-time measurement of down hole formation properties while the hole is being drilled
through the use of specialty tools integrated directly into the BHA. LWD tools can measuremost of the same formation properties that can be done with conventional logging tools run on
wireline. The use of LWD tools ensures that some measurement of the subsurface formation
properties is captured in the event that wireline operations are not possible. Additionally, realtime nature of LWD data can be used to guide well placement so that the wellbore remains
within the zone of interest.

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MWD – Measurement While Drilling
The real-time measurement of down hole drilling parameters while the hole is being drilled
through the use of specialty tools integrated directly into the BHA. MWD tools are used tomeasure down hole pressure and temperature, and the trajectory of the well (hole angle anddirection) which is critical when drilling a directional well or ensuring that a vertical well remains
vertical.
ROP – Rate of Penetration
The speed at which a drill bit drills through subsurface formations thus deepening and extending
the length of the wellbore. The speed is usually measured in terms of feet per hour or meters
per hour.
RSS – Rotary Steerable System
A specialty tool incorporated into a BHA used in directional wells that allows the bit to beoriented in the desired direction while continuously rotating the drilling string. Drilling parameter
instructions can be sent from the surface to the tool which then gradually steers the bit in thedesired direction. The tool replaces conventional directional drilling tools and provides better
control over the trajectory of the well, improved drilling performance and reduced wellbore
tortuosity. Rotary steerable systems are most commonly used when drilling directional,
horizontal, or extended-reach wells, but they are increasingly being used in vertical wells tooffset any down hole conditions that may cause a deviation of the wellbore and thereby ensurethat the well remains vertical.
TD – Total Depth
A term generally used to refer to the final total depth of a well. The TD of a well is defined by
two terms – the Measured Depth (MD) which is the overall length of the well as measured by
the length of the drill pipe required to reach bottom, and the True Vertical Depth (TVD) which isthe vertical distance between the surface and the bottom of the hole. The MD will always begreater than the TVD in a directional well, while they would be expected to be the same in a
vertical well.
VME – Von Mises Equivalent (stress)
Tubulars, such as the marine riser, are subject to a tri-axial stress state due to the loads
imposed by three principle stresses – axial stress, bending stress and hoop stress. These three
types of stresses can be combined into a single uni-axial equivalent stress that is the Von Mises
Equivalent stress. This simplified expression of tri-axial stresses can be directly compared tothe tubular’s yield strength to determine whether the tubulars have sufficient strength towithstand the loads that they will be subjected to.
WOB – Weight on Bit

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The amount of downward force, measured in thousands of pounds, that is exerted on the drill bit
to overcome of the strength of the rock in order to drill and deepen the hole.

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