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Reducing Drilling Costs Through the Successful Implementation of a One-Run Monobore Well StrategyTim Beaton, SHEAR BITS, Ryan Veloso, CNRL, Kevin Kowbel, CNRL, Leo Specht, Pacesetter DirectionalDrilling, Chris Afseth, Pacesetter Directional Drilling, J.J. Herman, SHEAR BITS

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September2 October 2013.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

As horizontal drilling programs continue to proliferate across the industry, and new technologies and operational practices

are developed and advanced, the reality of a one-run well has emerged. In various applications across several provinces in

Western Canada, the ultimate goal of drilling a horizontal well in one run from surface casing has been realized. This successcomes as a function of the combined effort of the operator, directional drilling company and PDC bit company to solve the

multitude of technical challenges facing a monobore strategy in areas with hole stability issues.

While many horizontal applications are now utilizing a monobore (one hole size) well plan below surface casing, the vast

majority of those applications have one critical aspect in common - the upper hole sections are in very stable formations that

can be left open for long periods of time. This is a critical aspect due to the fact that nearly all horizontal wells require

multiple bits and multiple BHA configurations to reach total depth (TD). In areas where hole stability is an issue, an

intermediate hole section is typically included in the well plan to seal off the unstable formations to allow the lateral intervalof the well to be completed. In addition to the added time and costs required to set an intermediate string of casing, this type

of well plan also results in a smaller hole size in the horizontal section.

In order to complete a horizontal monobore well through unstable formations, the well must be drilled in a very short period

of time and must be drilled with excellent hole quality to eliminate any issues with rapidly completing the wells. This paper

will detail a variety of these types of applications that successfully reached TD in 4-6 days from surface casing and were

completed without problems.

This rapid monobore well approach leads to both huge cost savings for the well and a larger hole size in the reservoir for

improved production. The result is more economical wells, drilled in much less time than conventional wells that yieldgreater returns.

Background

The process of drilling a deep well for oil or gas is an extraordinarily complex undertaking that has seen constant

development for over a century. In the past few decades, many plays that were historically uneconomical have become

viable due to new methods and equipment. One of the most influential developments in the recent past that has changed the

industry is the common use of a horizontal well design. The first horizontal oil well in recorded history was near Texon,

Texas in 1929, but the practice did not become common in the industry until later in the 20thcentury when downhole

technology allowed this type of well to be commercially viable (Helms, L., DMR Newsletter). Some of the criticaldevelopments that contributed to the expansion of horizontal well programs were improved downhole directional motors that

provided both power and orientation to the drill bit, and measurement while drilling (MWD) tools that communicated thelocation of the bottom hole assembly (BHA) to the rig crew. As with any well, regardless of trajectory or path, the economic

viability is directly related to the costs required to produce the well, and those costs are directly related to how long it takes to


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drill the well to total depth (TD). While there are many influencing factors, tools and technologies related to the time

required to drill a well, in the majority of cases, that time is dictated by the performance of the drill bit and the bottom hole

assembly (BHA).

A major factor in the proliferation of horizontal well plans over the last 10 years has been a corresponding increase in the

performance of drill bits and BHAs. Early attempts to drill lateral sections with directional assemblies, especially through

competent formations, required multiple trips due to insufficient bit durability, poor steerability or BHA component failure.

Horizontal wells also typically include a well design with a relatively short radius, equating to a high build rate between thevertical and horizontal portions of the well (dog leg severity (DLS) of 8-14 / 100ft is common practice). In the latter part of

the 20thcentury, and into the first decade of the 21stcentury, achieving aggressive build rates often meant using rollercone

drill bits due to the smooth torque response they produce with directional assemblies. Using PDC drill bits, which aregenerally a lot more durable and can drill longer sections at a higher rate of penetration (ROP), was challenging as the

technology in the drill bits and BHAs did not allow for con sistent performance in high build rate scenarios. Further, because

rollercone drill bits were the standard for these applications, and since rollercone drill bits have limited useful life (drilling

hours are limited by the life of the bearings & seals), it was common practice to run different bits in the build and lateral

portions of the well. In many cases, multiple bit runs were required to complete the curve, even in relatively short intervals.

There are many options to consider when designing a horizontal well. In addition to the ability of any given drill bit or BHA

to complete an interval, the stability of the well must also is considered. In many situations, the casing plan for a well has

less to do with the ability to complete a given interval in one run and more to do with isolating a section of the interval to

prevent undesirable issues. Some of these issues might include lost circulation, where the drilling fluid (mud) could enter theformation in large quantities, or sloughing shale or sand where the formation could collapse into the wellbore. There couldalso be areas of high formation pressure that would require a high mud weight to prevent the formation from collapsing orflowing into the well, where carrying a high mud weight would dramatically limit performance further along in the well(higher mud weight nearly always equals lower ROP). It is critical that the successful drilling of a well be performed in

consideration of the successful completion of the well. Especially in wells that have an aggressive directional plan (such as a

short radius build), a good quality wellbore is essential to allow casing to be run without issues. In many cases, when drilling

an aggressive build, it is all too common to have severe local dog legs in the well that can make the well path quite tortuous

and therefore make running casing very challenging.

Throughout the first decade of the 21 stcentury, directional drilling companies and drill bit companies worked aggressively to

develop new tools, bits and methods to successfully and reliably drill short radius wellbores with PDC drill bits. This process

included a wide range of new technologies including more steerable and more durable PDC bits, more reliable MWD tools,

and more powerful and durable positive displacement motors (PDMs). As a result of this development work, it is nowcommonplace to drill horizontal wells with PDC drill bits, and thanks to dramatic increases in drill bit durability, it is not atall uncommon to drill the build and lateral sections of a well in one run. While it is still highly uncommon, the final step in

this process is to drill the entire well in one run below surface, including the vertical, build and lateral sections of the well.

Monobore wells are not unknown in the industry, but the application of this well design has been limited to very specialized

applications. In many cases, monobore wells are created by using expandable drilling tools and expandable casing, but thispaper will focus on traditional monobore applications using fixed-diameter drill bits and standard casing and liners. There

are many examples in the literature of the benefits of monobore well designs, including frequent references to dramatic cost

and time savings (Corson 2006, Garcia 2001). Additional benefits are increased probability of getting logs and casing to

bottom due to larger hole sizes at TD, and enhanced formation evaluation as the upper sections of the borehole are still open

when logs are run prior to casing off the entire well (Randell 2012). Monobore wells are also much safer than conventional

wells as there are less trips and greatly reduced pipe handling requirements (Macfarlane 1998).

This paper will highlight three separate plays in Western Canada where a monobore strategy has been successfullyimplemented for horizontal well designs (noted by the blue stars in Fig. 1). In each of these situations, the success of the

endeavor was due to a concentrated effort on behalf of the operator and service companies to customize the tools and

methods used to drill and complete each well in a minimal amount of time. All of the wells detailed in this paper include a

surface section that will not be discussed as the improvements presented in this paper all deal with the main hole section of

the wells.


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Fig. 1: Map showing the three areas in Western Canada where monobore well designs are being developed

Spearfish Formation Southeast Manitoba

The first of the four formations that was drilled by the operator using a monobore well design was the Spearfish formation in

southeast Manitoba. The Lower Amaranth pools in Manitoba (Spearfish equivalent) are generally found at a depth of around

3,000 ft true vertical depth (TVD) and the formation thickness is normally less than 100 ft. The reservoir is typically found

in both coarse siltstones and sandstones (Barchyn 1982). The first wells drilled through the Spearfish formation were vertical

wells completed as early as the 1950s, but production rates were limited due to the technologies available at the time. Latein the first decade of the 21stcentury, advanced horizontal well drilling and fracturing technology was applied to this field

and resulted in production rates that were many times greater than the conventional vertical wells (Redekop 2010, Chodzicki

2003).

The first monobore Spearfish well drilled by the operator and the directional drilling company was successfully drilled in

early 2011 using one bit and one run at an average ROP of 98 ft/hr. This run used a 7-7/8 diameter, 5 bladed,13mm cutter

PDC drill bit to complete the entire well. Eleven more wells were drilled by the operator and directional drilling company

using a variety of different drill bits and the average ROP improved during this process to 130 ft/hr. The faster runs werecompleted with 4 bladed PDC bits with 13mm cutters, but performance was inconsistent, primarily due to bit ballingconcerns.

At that time, in early 2012, the PDC drill bit company became part of the development team for this play. The bit design

created for this application was a 4 bladed bit with 13mm diameter cutters and included extensive customized geometry to

meet the well requirements. The cutter profile on the bit is very short, which helps to achieve the aggressive build ratesrequired for the short radius well design. However, the gage pads on the bit are longer than standard, with a high degree of

spiral, which helps to make very consistent build rates (lower local DLS) and also helps the bit to track effectively in the

horizontal section of the well. When drilling with a conventional bent-housing directional motor assembly, the ROP when

sliding (when the drill pipe is not being rotated at surface) is a small fraction of the ROP when rotating (when the drill pipe is

being rotated at surface). This effect is primarily due to the fact that static friction is a much larger value than dynamic

friction, so the energy required to move the pipe forward when it is not rotating is a great deal higher than when it is rotating.

Therefore, in sliding mode, when the bit is being oriented by the bent-housing motor to initiate a directional change in thewell path, it is difficult to get consistent weight to the drill bit. This is especially true as the lateral displacement from the rig

location increases throughout the drilling of the horizontal leg of the well. The ability to stay on the desired path in the lateralportion of the well therefore reduces required sliding time and dramatically improves overall ROP.

In order to maximize the ability of the bit to evacuate cuttings, especially when drilling at a high instantaneous ROP (in this

application it is common to get above 300 ft/hr), the bit was designed to be manufactured with a steel body. Because the

structural strength of steel is over two times greater than that of a conventional matrix PDC bit body, it is possible to makethe blades of the bit much taller and thinner than can be reliably produced with a matrix-bodied bit. This allows a steel-

bodied PDC bit design to achieve a much higher face volume (FV) and junk slot area (JSA) than a matrix-bodied drill bit,

thus creating lots of open space to evacuate the high volume of cuttings that is produced when drilling at a high ROP.


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Unfortunately, the first well drilled with this new bit design was not a

top performer due to issues that required adjusting the directional well

plan during the drilling of the well. The second run completed by the

focus team, also using the 4 bladed 13mm cutter PDC bit mentioned

above, matched the average offset ROP of 130 ft/hr. However, upon

reviewing the run data, the PDC bit company determined that the bit

was not cleaning efficiently and a computational fluid dynamics

(CFD) analysis was performed to optimize the nozzle size andplacement on the bit to maximize the efficiency of cuttings

evacuation. The study resulted in a new hydraulic configuration that

proved to dramatically increase ROP on subsequent wells. The nextsix wells drilled with the same bit design and the same BHA

produced an average ROP of 162 ft/hr, an improvement of 25%. The

fastest well in that group of six wells with this same bit and BHA

recorded an average ROP of 188 ft/hr while drilling one of the longest

wells for the operator in this application, at 6,969 ft measured depth

(the average MD was only 6,286 ft).

Glauconite Formation

Southeast Alberta

The development of a one-run to TD monobore well strategy in the glauconitic sandstone play in southeast Alberta proved to

be a more significant challenge than the Spearfish application in Manitoba. This formation is surrounded by a much wider

variety of lithologies and the process of getting to the reservoir includes drilling through very significant transitions (Hayes

2008).

As shown in Fig. 3, the first monobore well drilled in this application did reach TD in one run using a 7-7/8 diameter, 5

bladed PDC bit with 13mm cutters. The second monobore well drilled in this play did not go as smoothly as problems with

hole condition led to a BHA failure that required a fishing operation and sidetrack. However, despite these problems, thewell was still completed in just over 13 days from spud, which was well within the range of conventional wells in this

application.

Fig. 3: Days versus depth curve for a series of monobore glauconitic sandstone wells in Alberta

Fig. 2: CFD analysis graphical result showingthe direction and velocity of fluid flow


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The conventional wells, which included setting an intermediate casing string and then drilling the horizontal section of the

well in a smaller diameter hole size, were commonly finished in 10-14 days from spud. So, even despite the problems with

the second well, the result was still very positive as drilling was completed in a similar time to the conventional wells, but

yielded a much larger hole diameter at TD (7-7/8 vs. 6-1/8) which made running logs and liners more efficient and also

enhanced production capacity. Additionally, no issues were encountered in completing the well, despite the borehole

remaining open for a longer time than normal.

One of the most critical steps in optimizing the BHA was realized through an extensive torque & drag analysis of theproposed well. This type of analysis allows the directional drilling company to customize the BHA configuration to

minimize the mechanical energy losses from the BHA interacting with the hole wall, thus delivering more reliable power to

the drill bit to enhance performance. In the study of this application it was discovered that performance could be optimizedby repositioning the heavy weight drill pipe (HWDP) after the completion of

the vertical and build portions of the well, in order to reduce the drag in the

lateral section of the well and enhance the transfer of weight through the

downhole motor to the drill bit. This became the standard practice for the

applications in this field and the remaining wells were successfully drilled in

similar fashion. The third well drilled in the sequence followed this strategy,

was the longest run in this data set, and the entire well was drilled in one run

with a trip to adjust the placement of the HWDP.

Once again, as with the Spearfish application, the PDC bit company was ableto develop a 4 bladed PDC bit with 13mm cutters that outperformed the 5bladed, 13mm cutter bits utilized earlier on in the drilling program. Thedifficult transitions encountered in the build section of these wells was

particularly well suited to the design configuration of this PDC bit as it is

developed and manufactured to be customized for each well, to match the

torque response of the bit to the application. In this case the bit was created to

tightly control torque fluctuations when drilling through transitions, giving the

directional drilling company the ability to accurately guide the bit along the

intended well path. The fastest well drilled in this sequence averaged 164 ft/hr

over a total distance drilled of 4,731 ft. Interestingly, this is many times faster

than a high ROP strategy employed to drill these wells in the late 1990s,

using a much smaller diameter drill bit (Eslborg 1996).

Midale Formation Southeast Saskatchewan

The Midale application has been an active play for decades in the Western Canada sedimentary basin. Extensive studies have

been completed to catalog the changes that have occurred in this play from the days of early vertical wells, through an

extensive waterflood, and now into a new age of unconventional horizontal fracturing completions (Schnegerger 1989, Galas1994, Mullane 1996, Pendrigh 2005).

The conventional method to drill wells in the Midale play is to drill the vertical and build sections with an intermediate hole

size, generally using 8-3/4diameter 5 or 6 bladed 13mm cutter bits, and then set casing at the end of the build. The lateral

section of the well is then generally drilled with a 6-1/4 diameter rollercone drill bit. After extensive development in this

field, the operator began to see very consistent performance using this conventional well design. The directional drilling

equipment and the drill bits became very reliable, producing a total drilling time for the well between 6.5 and 7.5 days from

spud over the course of many wells. In an effort to continue to reduce the total time required to drill the well, it wasconsidered to attempt a monobore strategy. After weighing all the factors involved, and considering how quickly the wells

were already being drilled with the conventional strategy, the risk of hole issues was deemed acceptable and the process

began to optimize a monobore well design.

The biggest challenge with the monobore strategy is to match the performance of the conventional system without the need

for multiple trips or multiple hole sizes. However, each portion of the well demands special characteristics to maximize

performance. For example, in order to achieve the aggressive build rates required in the curve portion of the well, it is

common to use a very high bend setting in the downhole motor. However in order to maximize ROP in both the vertical and

lateral sections of the well, it is preferred to use a relatively low bend setting so that the entire BHA can be rotated at a high

RPM. When each of the sections of the well is being drilled with a separate BHA, it is easy to customize each BHA and each

Fig. 4: The custom-designed 4 bladed,

13mm cutter PDC bit developedfor monobore wells


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drill bit to that portion of the well. However, when the entire well is being drilled in one run with one BHA and one drill bit,

it is obviously much more difficult to optimize performance in each section of the well. If, for example, the build is deemed

the most important section of the well (staying on the intended well path is critical to ensure that the horizontal section of the

well exposes as much of the reservoir as possible), then that would tend to dictate a BHA and drill bit which are best suited to

aggressive DLS and smooth steerability. However, using a motor with a large bend angle and bit that is created for

aggressive DLS will compromise ROP potential in the vertical section of the well and will require more sliding in the lateral

section of the well to maintain the desired horizontal trajectory (a bit that builds angle aggressively in the curve will drop just

as aggressively in the lateral).

The key to making significant advancements in drilling performance is through rapidly applied, customized technology and

products. In the case of the monobore Midale well, the target was to match the offset ROP average of 100 ft/hr, withinstantaneous ROP over 300 ft/hr in the vertical section, aggressive build rates in the curve, and complete a lateral interval of

around 2,000 ft. The solutions presented by the directional drilling company and the PDC drill bit company included

customized products and strategies designed to meet these challenges. In order to maximize reliability of the downhole

motor, the directional drilling company proposed a 2 fixed bend angle motor and in order to provide the bit with the power

required to achieve this aggressive performance, a 7/8 lobe count power section with 4.8 stages. The PDC bit company again

developed a customized 4 bladed, 13mm cutter drill bit manufactured to match the motor proposed by the directional drilling

company.

The results of this customized bit and BHA exceeded expectations. The system drilled 6,897 ft at an average of 128 ft/hr for

the entire well. This represents an ROP increase over the average offset by over 30% while also drilling the entire well inone run, thus eliminating days off the drilling curve. By drilling the entire well in one run, cost reductions of up to 40% wererealized, and by keeping the open hole exposure below 6 days, the well remained stable and liners were run to bottom with noissues.

Fig. 5: Days versus depth curve for a series of monobore Midale wells in Saskatchewan


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Conclusions

Three applications in the Western Canadian Sedimentary Basin have been successfully converted to monobore well designs.

In all three formations, a systematic development process involving the operator, the directional drilling company and the

PDC drill bit company was completed to optimize operating practices, and custom-match BHA design and drill bit design.This approach yielded dramatic improvements in drilling performance, increasing average ROP compared to conventional

well designs, even when drilling the entire well in one run and drilling a larger hole diameter in the horizontal interval.

This achievement represents a multi-fold improvement over the conventional practice. The wells are being drilled in much

less time than with the conventional method, in some cases almost twice as fast, and with one BHA and one drill bit, which

equates to up to 40% savings in well costs. The horizontal interval of the wells is being drilled with a larger hole size, which

makes running logs and liners much more efficient and leaves a greater capacity for production. Finally, and not least

importantly, the safety of the overall operation has increased significantly due to a huge reduction in the amount of tubulars

that must be handled to drill and complete each well.

Acknowledgements

The authors would like to thank Canadian Natural Resources Ltd., Pacesetter Directional Drilling Ltd. and SHEAR BITSLtd. for permission to publish this paper. The authors also wish to thank Nelson Yarmaloy of Pacesetter and Sid Isnor of

SHEAR BITS for their help in compiling the data presented in this paper.

Nomenclature

BHA = Bottom Hole Assembly

CFD = Computational Fluid Dynamics

DLS = Dog Leg Severity

FV = Face Volume

HWDP = Heavy Weight Drill Pipe

JSA = Junk Slot AreaMD = Measured DepthMW = Mud WeightMWD = Measurement While Drilling Tool

PDC = Polycrystalline Diamond Compact, used to describe a type of fixed cutter drill bit

PDM = Positive Displacement Motor

ROP = Rate of Penetration

TD = Total Depth

TFA = Total Flow Area

TVD = True Vertical Depth

WOB = Weight on Bit


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