1. Texas Tech University
Chesapeake Energy Internship 2016
Field Engineer Internship
Matthew Peter Barten
ENGR 3000
Shannon Younger
September 7, 2016
2. Table of Contents
What is Chesapeake?.................................................................................................................... 4
Why the energy industry?............................................................................................................ 4
Where I was located...................................................................................................................... 5
What I learned............................................................................................................................... 5
Discovery.................................................................................................................................... 6
Drilling........................................................................................................................................ 7
Completions.............................................................................................................................. 10
Production................................................................................................................................. 10
Artificial Lift............................................................................................................................. 14
Plug and Abandon..................................................................................................................... 15
Salt Water Disposal................................................................................................................... 15
My Project ................................................................................................................................... 16
Introduction............................................................................................................................... 16
Considerations & Constraints ................................................................................................... 19
Design Tool............................................................................................................................... 21
Design Process.......................................................................................................................... 22
Manufacturing........................................................................................................................... 28
Economic Analysis ................................................................................................................... 28
Testing....................................................................................................................................... 30
4. What is Chesapeake?
Chesapeake Energy is an exploration and production (E&P) company that is
headquartered in Oklahoma City (“Corporate Fact Sheet” 1). It is the second largest producer of
natural gas in the United States and is the thirteenth largest producer of oil and gas in the country
as well, with production of 248 million barrels of oil equivalent (mmboe) per year (“Corporate
Fact Sheet” 1). It also employs 4,400 employees and has 1.5 billion barrels of oil equivalent
(bboe) in proven reserves (“Corporate Fact Sheet” 1). Like many E&P companies, Chesapeake
is active in many states, which provides exciting engineering opportunities and is one of the main
reasons why I want to work in the energy industry.
Figure 1-Map of Chesapeake's oil field locations
Why the energy industry?
I am interested in working in the energy industry because of the direct impact that it has
on people’s lives, the interesting projects and the complexity. The ability of the energy industry
to provide families with electricity, fuel, plastics, and other useful products has always been very
5. interesting to me. I want to be able to contribute to people’s lives, and working in the energy
industry would be a good way to do so.
There are multiple types of energy companies: upstream, midstream, and downstream.
Downstream energy companies deal mainly with refining crude oil and gas into consumables,
like plastic and gasoline. Midstream companies are mainly concerned with the transportation of
gas and oil through pipelines. Upstream, or E&P companies like Chesapeake, are responsible for
getting the raw material to the surface, through a variety of drilling, completion, and production
techniques.
With all these different methods, E&P companies provide a great opportunity to work on
the very interesting projects that are produced by this sector. This is especially true of
exploration and production companies such as Chesapeake Energy. In this part of the energy
industry, there are a lot of unique problems to contend with out in the field such as corrosion,
erosion, geological issues, and complex machinery troubleshooting.
Where I was located
This summer I was located in the small town of Waynoka, Oklahoma. Although
Waynoka is only a town of about 1,000 people, the field office is responsible for a large swath of
northwestern Oklahoma. With this large area of responsibility also comes some unique
challenges. The biggest challenge that the Waynoka field office faces is not what one might
expect. It is not corrosion as one might expect dealing with chemicals, but it is water. To be
more specific, it is the produced water that comes up with the oil and gas from the wellbore.
This water is three times saltier than the ocean and is contaminated with other trace elements.
This problem is so large that a whole section of this report is devoted to explaining how
Chesapeake deals with this problem.
What I learned
This part of the paper will discuss everything that I was taught and what I observed this
summer from my exposure to the field. This part of the paper will mainly discuss what I learned
about the lifecycle of a typical well in the Waynoka area; from rock hounds (geologists) to the
pumpers (lease operators). The first point to recognize, is that this cycle is very complicated and
expensive. First, the geologists must find a play with their tools and training. After that, the
mineral rights are secured and drilling begins. Third, the well is completed by hydraulic
fracturing methods which employ a plethora of technologies. Next, the production equipment is
installed and the well starts to produce using a variety of different methods. Produced water
must also be disposed of throughout the production cycle of a well. Finally, as the wells
production declines, it is plugged and abandoned.
6. Discovery
The first stage in the lifecycle of a well is the identification of a “play”. A play is an area
that geologists have identified as containing substantial amounts of oil and gas. These plays can
vary, trapping the gas and oil differently. The types of traps are structural, stratigraphic, and
combination (Institute of Gas Technology 15-18). Structural traps are when the shape of
reservoir rock is the method that confines the oil and gas. These tend to be the easiest to
discover (Institute of Gas Technology 15-18).
Figure 2- Schematic of a Drilling Rig
7. Stratigraphic traps are present when oil and gas is trapped in the stratigraphic layers of rock due
to a permeability change in the rock; these types of oil traps are harder to discover (Institute of
Gas Technology 15-18). The final type of trap is a combinations trap, having attributes of both
types of the other traps; some offshore plays are an example of this type of trap (Institute of Gas
Technology 15-18). These traps are usually found by geologists examining outcroppings of
layers, chemical signatures or the popular seismic testing (Institute of Gas Technology 19-25).
Once a reservoir is proven it is time to start developing the play.
Drilling
To begin drilling, the mineral rights must first be secured from the owners. In some
cases, the mineral rights holder is different from that of the land owner. In the case of the United
States, about one-third of the mineral rights are owned by the government, while in others all
mineral rights are held by the government. To secure these rights a lease is signed, meaning the
use of the mineral rights is temporary. Once the legalities are complete, it is time to start
drilling.
A drilling site is a complicated system, which requires everything to work in tandem (fig
2). The place where the whole process starts is the generators which uses fuel to supply the
whole rig with electricity to run the assortment of equipment. Normally the rig drills by turning
the pipe which turns the bit at the end of the drill string (connected pipe downhole). After each
part of a well is drilled, a steel pipe barrier (casing) is cemented into place downhole. The casing
is what prevents groundwater intrusion into wells and fluid intrusion into the groundwater.
Although the drilling itself is straight forward, the mud circulation system adds some
complexity.
Figure 3-Picture of a shaker
8. A good place to start the mud cycle is
at the mud pumps (#32 in fig. 2). These
pumps are responsible for pumping the mud
down the drill pipe. The mud’s properties are
managed by adding material using the mud
hopper (#30 in fig 2) and the mud is mixed
with the mud mixing pumps (#31 in fig. 2).
The mud is then stored and pumped down the
spinning drill pipe from the mud tanks (#28 in
fig. 2). The purpose of the mud is to provide a
head pressure to keep gas downhole, provide
stability to the well bore and carry the cuttings
to the surface. Once mud containing the
cuttings is returned it enters the shale shaker
(#22 in fig. 2, fig. 2). The purpose of the
shaker is to vibrate the cuttings out of the mud.
The mud then moves into the degasser (#23 in
fig. 2). The degasser is a piece of equipment
that, as the name suggests, removes gas from
the mud, preventing bubbles from forming.
From this stage the mud travels to the
desander (#24 in fig. 2) which removes solids
that the shaker missed. The last stage the mud
goes through is the mud cleaner (#25 in fig. 2),
which removes the last impurities. From this
stage, the mud is returned to the mud tanks for
recirculation. Other important equipment
needed for the safety of the workers and the
environment is also on a drilling site.
The first machine that helps ensure
safety is the Mud Gas Separator (#21 in fig. 2,
fig. 4). The job of this separator is to release
the gas from mud in the case of a kick. A kick
is when the hydrostatic pressure of the mud
falls below the pressure of the formation and
gas starts coming to the surface in the mud.
As this occurs, the gas increases in volume,
which creates a dangerous situation as there is
a danger of sparks. If the Mud Gas Separator
is operating correctly, then the gas will be
Figure 4-Mud Gas Separator
9. routed to the flare (#20 in fig. 2), where it is
harmlessly burned. If the separator is not
functioning correctly and the kick endangers
the drillers, the Blowout Preventer (BOP) will
be used.
The most important piece of safety
equipment on a drilling site is a blowout
preventer (BOP) (fig. 5). The job of a BOP is
to close the wellbore off in the case of an
uncontrollable kick. There are many types of
BOPs; one type only restrict flow around the
drill pipe (pipe rams), another shears the pipe
and seals the hole (shear rams), and one just
shuts the well (blind rams). At most sites, there
will be multiple BOPs stacked on top of each
other and they are tested consistently to
guarantee the safety of everybody on the well
site. Other than the safety equipment, there is
also specialized drilling equipment.
One piece of specialize drilling
equipment is the motor (fig. 6). This special
piece of equipment is a part of the assembly at
the end of the drill string. The motor itself has
a slight bend in it and allows the drill bit to
continue cutting while the rest of the string is
stationary. This ability combined with the
small bend, lets companies directionally drill.
The driller will alternate between sliding
(directional drilling) and rotary drilling (drilling
straight) to curve the well into the correct
formations. The next piece of equipment also
helps companies with directional drilling. The
measure while drilling (MWD) tool is a tool
that is also at the end of the drill string above
the motor. This tool sends pulses of
information through the mud up to a technician
who examines the data consisting of inclination
and direction. This data is then passed on to the
driller who uses this data to drill. The three
Figure 5-Blowout Preventer (BOP)
Figure 6-Directional Drilling Motor
10. types of MWD tools are an EM, APS, and retrievable. The EM tool does not require mud pulses
to relay the data, but uses EM waves to transmit to the surface. The only downside is that the
tool is expensive, sensitive to metal deposits, and has a limited battery life. The APS tool is
cheaper, and has a good battery life. Its downside is that it requires mud to transmit data. The
final tool is retrievable; it has the longest battery life, can handle more torque on the string and
can be disconnected downhole. Like APS though, the retrievable tool requires mud to transmit
data.
As one can see, the drilling process is very involved and has many complicated systems
all working together to complete the task of drilling into a formation. Once the drilling is
completed, it is time to complete the well so it can begin to produce.
Completions
The completion of the well means that it is being prepared for production. Although
there are many types of completion methods, the one that I was exposed to in the field was
cased-hole completion. This means that the casing was cemented into place during drilling and
that in the completions phase it will need to be perforated. Perforation is done by lowering a tool
with explosive charges loaded on it using a wireline truck. This tool along with a packer is
lowered into the hole. When the perforation gun reaches the correct depth, it is activated,
shooting long holes through the casing. Once the casing has been perforated, the packer is
installed. A packer is a piece of equipment that controls the flow between stages along the
length of the casing. This allows for a multi zone completion of a well.
Once the well has been perforated and isolated, the zone will be completed. This
completion is done by pressurizing the casing and pumping proppant downhole. The high
pressure in the casing and the use of viscous fluids causes the rock around the perforations to
fracture. The proppant (small grains derived from sand) fills these cracks, allowing them to stay
open once fracturing is complete. Once this is complete, subsequent stages are completed the
same way. One difficulty with this completion method is that hydraulic fracturing is water
intensive, requiring about 10,000 bbl of water per day of operation. However, at my location
they were consuming produced water from our wells instead of freshwater like in many
locations. It is important to stress the importance of the completion step. If it were not for this
step, horizontal wells would not be economical. Furthermore, some oil and gas reserves would
be inaccessible for development.
Production
Production is an important step, because it is responsible for the capture and sale of oil
and gas. Production is simple in its execution; install the equipment, test and start producing.
This section will cover the installation, testing and purpose of production equipment.
Before any equipment is installed, the containment is built. The containment surrounds
only the production equipment, leaving the wellhead and compressors (if there are any) outside
the protected area. Usually the containment consists of a liner covering the ground, including an
11. earth berm that surrounds the containment area. Then the liner, including the berm part, is
covered with gravel. After the containment is completed, the production equipment is installed.
The production equipment is lifted into the containment with the assistance of a crane. Once the
production equipment is in place, piping will be installed, connecting all the equipment together
and finishing the installation. Before the well is allowed to produce pressure testing and the pre-
startup safety review (PSSR) is done. The PSSR confirms that the well pad is built to the design
specifications and that there are no other safety concerns. Once the PSSR and testing is finished,
the well is allowed to produce.
Now that the installation has been covered, the types of production equipment will be
reviewed. The first piece of production equipment to cover is the well head (fig. 7). The typical
wellhead at my field location consisted of a Christmas Tree, an emergency shutdown valve
(ESDV) and a motor valve. The Christmas Tree is the part of the wellhead that consists of
valves. Its purpose is to control the flow from the wellhead, and is mainly used to shut the well
in during maintenance. The second part of the wellhead is the ESDV. This emergency device
will shut the well in if certain conditions are met; such as dangerous pressure. The final part of
the wellhead is the motor valve. This valve can be customized to open and shut under certain
pressure, flow and time conditions. This allows the lease operator to control production from the
well.
From the wellhead, the flowline proceeds to a three phase separator (fig. 8). Three phase
separator, free water knockout, knockout, or FWKO are all proper names for this vessel. This
production equipment relies on the principle of density to separate gas, oil and water. Some gas
Figure 7-Wellhead
12. is left in the vessel to maintain the pressure needed to move the liquids to their next destination.
The rest of the gas proceeds through meters into a common pipe. This pipe supplies gas to
instrumentation, the sales line and possibly a compressor. The water from the FWKO
equipment is then sent to water tanks, while the oil is routed to the heater treater (fig. 9).
13. The heater treater is used to further separate gas, oil and water using heat. These vessels
can be vertical or horizontal. The heater treater uses gas from itself and the common gas header
to keep a flame going in a fire tube. This fire tube is inside of the vessels and causes gas, water,
and oil to separate further. Gas goes into the common gas line, water goes to the water tanks and
the oil goes to the oil tanks.
Once the water and oil reach the tanks, they start to fill. The oil tanks are emptied by
trucks which buy the oil and haul it away to be sent to a refinery. Although typically the water
tanks are also emptied by trucks, the Waynoka area has more produced water than other
Figure 8-FWKO
Figure 9-Heater Treater
14. locations. Therefore, Chesapeake had to implement innovative solutions, all of which will be
covered in the salt water disposal section.
Although production remains strong for several years to several decades, eventually the
well’s production will fall to a point that intervention is required. When this happens, artificial
lift methods are used to prolong the life of the well.
Artificial Lift
Artificial lift is typically implemented once there is not enough formation pressure to
push fluid to the surface. Without artificial lift, the wells would load up with fluid and
production would be impossible, but with the help of different artificial lift methods the lifespan
of the well can be prolonged. The types of artificial lift that will be discussed are: electric
submersible pump (ESP), gas lift, plunger lift, and rod lift.
The first method of artificial lift is the ESP. The ESP is lowered down in line with the
production string. The ESP uses electricity to pump liquid from downhole to the surface. The
advantages of this lift system is that it very efficient, variable and requires a smaller surface
footprint. Disadvantages include cavitation, sand and gas susceptibility (Ratern). Another
disadvantage is installation requires higher voltage power supply and the necessity of pulling the
production string for installation and repair (Ratern). However, this problem does not exist with
gas lift.
The second artificial lift method is gas lift. While ESPs use pumping to get fluid to the
surface, gas lift uses compressed gas to lighten the fluid column, which allows the fluid to flow
to the surface. This is done by compressing natural and sending it to down-hole valves. These
gas lift valves are spaced down the depth of the well and are calibrated to open at precise
pressures. The valves are designed to open from the uppermost valve first to the bottommost
valve last. This is done to allow the fluid to be taken off slowly from the top of the fluid column.
The benefits of this method are that the valves are more robust than ESPs. Moreover, some
setups even allow for the replacement of valves without having to pull up the production string.
The negative of this approach is that gas lift relies heavily on gas supplies. If there is not a
steady high-pressure supply from the well itself, then the well must use a pipeline. This can
cause additional problems if the line pressure in the pipeline is too low for the compressors to
utilize.
Plunger lift, the third method, is widely used in the oil field for older, slower producing
wells. In this method, a piston (plunger) with a small clearance in the production tubing is
inserted into the production string. The formation builds pressure behind the plunger until a
specified amount of time or activation conditions are met. Then the valve at the surface opens,
allowing the pressure to send the plunger upward with the fluid sitting above it. Once the
plunger reaches the surface, it is captured by a lubricator until the after flow of gas is complete;
then the plunger is dropped back down to start the cycle over again. This method of artificial lift
is so popular because there are few parts to fail in this setup, and the plunger can be replaced
15. easily due to wear and tear. The only downside is that the plunger will not return to the surface
if there is not enough gas pressure, or if there is too much fluid above the plunger.
The final type of artificial lift, rod lift, is one of the oldest and most recognizable. Rod
pumps operate using a very simple design. It uses an oscillating mechanical lever arm at the
surface to move a string of rods in the well which actuates a down-hole valve assembly. This
form of artificial lift is one of the cheapest and is utilized on wells that do not produce much gas.
Although it is very efficient in producing oil, it is very susceptible to gas locking (when gas
causes the valves to get stuck).
In conclusion, these methods use a variety of physical and engineering principles to solve
the problems caused by the loss of natural down-hole pressure. Also it is important to point out
that there is no “perfect method”. Each form of lift has its tradeoffs and preferable
environments, thus it is important for the wells to be analyzed before a certain form of lift is
implemented. Finally, it is important to mention that eventually even artificial lift methods
cannot keep a well producing. When this occurs, there is no choice but to plug and abandon.
Plug and Abandon
The abandonment of a well is akin to the production process in reverse. The production
equipment is removed and recycled on other projects if possible. Then the well is plugged and
the site is returned to pre-drilling appearance.
The removal of the production equipment occurs with the same type of equipment and
men that helped install them. All the reusable production equipment is transported to other sites,
while the old equipment is hauled away for disposal. After this is completed, it is time to plug
the well. The purpose of plugging a well is to prevent oil, gas and water from reaching the
surface or water table. In order to prevent this, concrete is used to plug the well. The production
tubing is removed first and then concrete plugs are poured at each casing section. The final step
is to remove the well head, and weld an identification plate to the casing. Once these steps are
finished, the well pad is returned to its pre-drilling environment. All of these steps abandonment
steps help reduce the environmental footprint of E&P energy companies.
Salt Water Disposal
Another part of the lifecycle of the well is the way produced water is dealt with. As
previously mentioned, salt water disposal is a large issue for the Waynoka field office. This
produced water is created as a byproduct of oil production. Unfortunately, this water is brinish
and contaminated with trace elements. Typically this water is not a large cut of the overall fluid
coming to the surface. What makes Waynoka unique is that the fluid produced in the field has a
3:1 ratio water to oil. This problem is made worse by the volume of water produced, roughly
165,000 barrels a day of produced water to be exact. This is about 50% of all produced water in
Chesapeake Energy. This extreme volume of water makes it impractical to haul the water away
by trucks. Instead, Chesapeake utilizes a water transfer pipeline to move water from wells to
centralized salt water disposal (SWD) locations.
16. These SWD then separate any trace oil from the water and re-inject the water back into
the earth. This is the most practical way to get rid of the water, because of the cost of
purification for drinking water and the stigma attached to produced water by environmental
organizations. Unfortunately, SWD’s have become more regulated in the last year due to the
increasing seismic activity in Oklahoma. These regulations have imposed strict limits on
Chesapeake Energy and other companies who have been injecting produced water into the
Arbuckle formation.
This has caused a great drive towards improving efficiency and finding other ingenious
ways of using/disposing of produced water. Examples include injecting into more seismically
stable zones, evaporation ponds, fracking, or even treatment of the water. The most explored so
far has been finding better injection zones and using the water for hydraulic fracturing
procedures, which saves the company the cost of using fresh water.
Besides the logistical problems the produced water causes, there are also reactivity issues.
This water causes a variety of problems, the first of which is the corrosion of parts and
processing equipment. So far, this problem has been solved with the use of material science,
using nonreactive materials like plexiglass, polymers and stainless steels. Examples of these
solutions are the old steel tanks that were used to store the produced water. After some corrosion
based failures the company switched over to plexiglass tanks. In fact, most of the piping that
deals with produced water is plexiglass, polyethylene, or stainless steel.
This concludes the lifecycle of a well. This part of the report showed the life of a well;
from the discovery of oil by geologists to the abandonment of the well by the company. This
portion also covered the main parts of a drilling rig, as well as the main production equipment
that is prevalent in the Waynoka region. Additionally, this portion covered the myriad of
artificial lift methods, as well as the salt water disposal procedures.
My Project
Introduction
The project that I worked on during my internship at Chesapeake Energy was to design
and evaluate a new float for a Free Water Knockout (FWKO). This project required me to call
upon many techniques, and skills that I have learned through the Edward E. Whitacre Jr. of
Engineering at Texas Tech. Examples of these are programming, statics, graphics, and material
sciences, all of which I used in the process of completing my project.
Before the project process can be discussed, some important background should be
reviewed. The first thing to cover is the FWKO. Its job is to separate oil, produced water and
gas from the pipe coming straight from the wellhead. This piece of equipment accomplishes its
goal by using the principle that gas is lighter than liquid and oil is lighter than water. This
17. principle is harnessed by allowing the gas to come off the liquid entering from the wellhead.
This gas then rises into a dome and out a valve located on top of the dome. The oil builds up on
top of the water until its level is high enough to crest a retaining wall, filling up the oil
compartment. The water compartment is filled by allowing the water from the bottom of the oil-
water mixture through a hole in the bottom of the water compartment. This will continue until
the compartments need to be emptied.
As the compartment is filling, the float is utilized. As the float rises on the increasing
liquid level, it puts more torque on a dump valve. Eventually, the net buoyant force is enough to
open the valve and release the liquid down to a manageable level. This is accomplished by the
trunnion, which is connected to the float’s rod on the inside of the FWKO, and a lever arm on the
outside. This lever arm is then connected to the dump valve allowing the buoyant force of the
float to actuate the valve. However, there are many problems that interfere with the simple
operation of the FWKO.
Figure 10-Pre-Failure Pit Figure 11-Pitting Corrosion Failure
Although FWKOs suffer from many problems, the biggest is corrosion. Corrosion is the
breaking down or destruction of a material, especially a metal, through chemical reactions.
Although corrosion is a regular occurrence almost everywhere in the oilfield, it is compounded
in FWKOs due to the high salinity and corrosive compounds in the produced water and oil
respectively. This situation was made worse by the carbon steel floats that the FWKOs used.
18. Under these conditions, a small pit turned into a fist sized hole. The current solution to this
problem was to replace carbon steel floats with stainless steel floats.
Although this solution was better than carbon steel, stainless steel was still not a perfect
solution. One issue with the stainless steel floats was the price. A stainless steel float costs $310
apiece, so there was room for a cheaper alternative. An additional problem was that the welds
were susceptible to leaks. After research, it was my opinion that the welds propensity for leaks
reduced the lifespan of the float to about 5-10 years, but closer to 5 years (ASM International 2-
8; Gooch 138-146). The final issue with the stainless solution was that the design still relied
upon encapsulating one large volume. This method made the float failure prone, because it
failed after only a small leak. All of these factors encouraged the development of a cheaper,
more resistant solution.
Figure 12-Stainless Float Figure 13-Stainless Float
19. Considerations & Constraints
Before designing the float, there were requirements of the float that needed to be
considered. There were many aspects to the float: dimensions, angle, torque, pressure resistance,
density, reactivity, pressure drops, and sensitivity. The first requirement that will be explored is
the variable length and diameter of the buoy.
Length and diameter are important to the float, because these are the characteristics that
determine the amount of net buoyant force the float has. The net buoyant force of an object is
the weight of the liquid volume displaced, meaning that the buoyant force of an object varies
proportionally to the volume of the float. However, since the weight of the float also grows
proportional to the volume, an object will only float if the buoyant force is larger than the weight
of the float. It is important to have a balance of weight and net upward force, because the net
upward force opens the dump valve, and the weight of the float closes it. This means the float
needs to have enough upward force to open the valve, yet enough weight to close it.
Furthermore, because I wanted a standard sized float for both water and oil sides of the FWKO,
the design must be able to work in both compartments.
There were also constraints to
remember. The biggest constraint for
the buoy dimensions is the diameter
and the total assembly length. For the
FWKO that I was designing for, the
distance from the trunnion to the back
of the compartment was about 45”.
However, it was decide that 35-40”
would allow for a better tolerance, and
some potential room to modify the
design if needed. Also the float has to
be able to fit through the 7” hole in the
FWKO.
Angle and torque were also
important considerations because it
requires torque to open and close the
dump valve, and angle is what causes
the available torque to change. To
understand this change in torque, one
must examine the forces being applied
to the rod and the torque equation
(Equation 1). The forces prevalent are
Torque=F*Cos ( 𝜃)*L
𝜃=Angle between lever arm and the force
L=Length of the lever arm
F=Force
Equation 1-Torque
Figure 14-Torque changes with the angle
20. the net buoyant force, and the force due to gravity; both of which act exclusively in the vertical
direction. Now using the torque equation, as the angle of the float increases, the result of cos(θ)
decreases; thus the overall torque also decreases(fig 10).
This was important because it meant that the new float should be designed to be able to
open and shut the valve at its minimum torque, which is the maximum displacement angle from
horizontal. According to the trunnions specifications, the maximum displacement angle from
horizontal is +/- 45 degrees. Since the trunnion sits in a pipe that leads into the bulk of the
FWKO, there was an additional constraint to calculate. After examining the pipe, trigonometry
was used to determine that the dimensions of the pipe constrained the maximum displacement
angle to +/- 24 degrees from horizontal. Afterward, I started to find the minimum amount of
torque that would be need to open the dump valve.
Finding the torque requirement
was not very complicated, as the
paperwork for the dump valves had a
torque table included. This table
showed the required torque to open
and close the dump valve at a specified
pressure drop. One difficulty was
determining if the pressure drop was
based on the hydrostatic pressure (the
pressure drop when the valve is closed)
or the flowing pressure drop (the
pressure drop when the valve is open). After some more research and informative calls to
Kimray, the manufacturer, it was determined that the pressure drop was calculated at flowing
conditions using an equation given on Kimray’s website (Kimray; Equation 2). Since the
equation depended on the specific gravity of the fluid traveling through the valve, maximums
and minimums would have to be analyzed. The range of specific gravity that was used for the
oil was 0.7-1.0 and the range that was used for the produced water was 1.14-1.16. Additionally,
a range of flow rates was needed. The oil flow rate range that was used was between 0 and 2,000
barrels a day (bbl/day), and the flow rate range that was used for the produced water was
between 0 and 5,000 bbl/day.
The final set of concerns that needed to be addressed before designing the float was the
materials to be implemented. There were a couple of material decisions that needed to be made.
The first material decision was which buoyancy material to implement in the design. The
previous two iterations of the float purely used the volume displaced by metal cylinders to
achieve buoyancy. However, as previously mentioned, these designs were susceptible to leaks.
This meant that the new design needed to use a material that was impervious, or at least resistant,
to water.
∆𝑃 = 𝐺 (
𝑄
𝐶 𝑉
)
2
𝐺 = 𝑆𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝐺𝑟𝑎𝑣𝑖𝑡𝑦
𝐶𝑣 = 𝑉𝑎𝑙𝑣𝑒 𝐹𝑙𝑜𝑤 𝐶𝑜𝑒𝑓𝑓𝑖𝑒𝑐𝑖𝑒𝑛𝑡
∆𝑃 = 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐷𝑟𝑜𝑝 (psi)
𝑄 = 𝐹𝑙𝑜𝑤 𝑅𝑎𝑡𝑒 (gpm)
Equation 2-Pressure Drop Equation
21. Since the FWKO can be pressured as high as 250 psi, the buoyancy material needed to be
pressure resistant; this is where previous models excelled. This would also mean that volume
loss due to the pressure should be taken into account. The next material constraint was the
reactive environment of the FWKO. Crude oil and the brine water have a variety of corrosive
combinations, causing the rapid oxidation of metals and degradation of other materials. This
meant that the material chosen for buoyancy must be resistant to the environment of the FWKO.
After researching and consultation, closed-cell polyurethane was chosen as the buoyancy
material for the new float. This foam was chosen because of its good chemical, pressure and
moisture resistance. In fact, this type of foam is utilized by deep sea remote operated vehicles
(ROV’s).
Design Tool
Once these constraints were realized, there were many calculations to complete. Initially,
the calculations were done in spread sheets. This method proved to be insufficient and too time
costly due to the complexity and amount of variables present. The next problem was the
evaluation of the data as well; there needed to be a way to comprehend the changes being made.
Another problem was that the user needed some visual aids to help in the analysis of the float.
The final problem was that there was no way to really have multiple designs; to save, open, and
compare them.
To combat these issues with the design process, a design tool was built in with Visual
Basic for Applications (VBA) in Excel (Appendix: Design Tool). VBA is a simple
programming language, similar to MatLab, which is included with all Microsoft Office
applications. The ability to program in Excel allows a designer to be able to input the equations
directly into the computer, versus recreating the equations by linking cells with formulas or by
hand calculating the equations. Additionally, coding a design tool allows the architect to
comment on their code. This allows future designers to understand and be able to change the
programming.
The technique that was chosen to organize the variety of inputs was to categorize similar
information together under headers. This organization scheme helps the user understand which
information is related, and what the possible effects are. For example, all the information for the
rod (length, outer diameter, inner diameter and density) was deposited under a header titled “Rod
Properties”. In addition, general properties like specific gravity, safety factor, flow rates, etc.
were all put under a header titled “General Properties”.
The grouping of values under headers also helped the evaluation of designs. This is
especially true for the “Results” and “Requirements” headers. The “Results” header is useful
because it puts all the changing values in one location so the user can see the alterations due to
different inputs. The “Requirements” header shows the results to calculations that return the
22. Figure 15-Dynamic Model
values that are required to activate the dump valve. By having both of these headers a user is
better equipped to determine the integrity of a design.
Another feature that also helps users comprehend the integrity and size of their design is
visual effects. The two main visual effects that are implemented in the design tool are traffic
lighting and a dynamic model. The first feature, traffic lighting, is a method by which
impossible values are given a “red light”, cautionary a “yellow light”, and acceptable a “green
light”. For example, if the calculated torque is not enough to open the dump valve, a red box
will appear next to the textbox, but if the torque is enough (including the safety factor) a green
box will appear. A yellow box only appears if the value is enough to open the valve, but it is not
larger than the given safety factor. This quick reference allows a user to quickly identify
problems with the design, which decreases the chances of overlooking a simple error.
The second visual effect implemented in the tool is a dynamic model. The dynamic
model is made up of pictures or shapes that represent the components of the float. These objects’
dimensions and locations are dependent on the variables entered into the tool. The result of this,
is that when values are changed in the tool, a scaled model is shown to the user. This allows the
user to see the relative size of each component, as well as the percentage of the float submerged
under water.
The final feature that is important to this tool is the ability to save and open previous
designs. Without this capability, the designer would have to record every variable before editing
or starting a new float design. It also means that instead of being required to input every
parameter by hand, the computer automatically loads all the data for the previous design into the
tool. This functionality increases the possibilities of design, as it allows the user to be able to
save each version of the design along the process of creating a new float. The next positive
aspect about these features is that it allows a user to effortlessly load other designs to compare
their results, as well as share their design with other users.
Design Process
This section discusses all the steps taken in the design process. The first step was to
evaluate the original stainless steel float design. Then, a variety of designs would be created in
23. the design tool. Lastly, the best design would be assessed many different ways in order to
determine the integrity of the design.
To evaluate the stainless steel design all that was needed was pipe dimensions and
density, as well as the length of the rods used. The pipe’s dimensions were easily measured to be
24” long, and 6” in diameter. However difficulty resulted when trying to find the density,
because the type of stainless steel pipe used to make the float was not known. This problem was
overcome with the help of one of the facilities engineers, Alan Duell, who had an ultrasonic
measuring device. An ultrasonic measuring device is a machine that uses sound to measure the
thickness of a material. The type of pipe determined by this method was schedule 10 stainless
steel. With this information, the weight per length of pipe was found to be 13.9 kg/m from a
pipe table and the thickness was found to be 3.41 mm.
After determining the properties, the float was evaluated using the design tool.
Evaluating the original was important because, it showed the excesses and inefficiencies in the
original blueprint. For example, when the original design was evaluated by the design tool, the
float was 96.4% submerged when put in a light oil environment (700kg/m^3). This meant that
the float had much more closing torque than opening torque available. This was most likely not
desirable, but necessary due to the weight of the stainless steel material and the amount of
volume needed to be displaced in order for the float to function. Despite this issue, the float was
confirmed to stay afloat and activate the valve in both the oil and water side.
Following the assessment of the original design, preliminary designs were explored. The
first one that was designed was a buoy with a large pipe core and a normal ¾” rod. The purpose
for the large core was to provide weight. Additionally, this large core was supposed to be able to
control the float by allowing lease operators to fill the core with sand to provide even more
weight. To attach the float to the rod, friction or adhesive was planned.
This design was initially very successful, but problems developed. The first major
problem with this design was friction and the adhesive might not keep the float secured over a
long period of time in the reactive environment of the FWKO. The final problem arose when it
was realized that a substantial portion of the cost for this float would come from the pipe and
Figure 16-Design tool model of the original float
24. fittings. All of which led to another, more economical option to be considered.
Figure 17-Design tool model of the “large core” design
Learning from mistakes in the first design, the second was much more conservative. The
subsequent design was the “continuous rod” model. This model was very simple, relying on
same sized piping for the rod, and washers to keep the float in place. This model also
implemented many money saving designs. The first of these money savings was to utilize one
sizing of pipe for the design. This meant that if these floats were manufactured in bulk the
supplier would only have to buy one size of piping, decreasing cut-off waste. Also, larger pipe
has a higher cost per length, so by reducing the size there was an additional cost savings. This
technique of downsizing was also applied to the float hardware.
The second set of changes that saved money was the reduction in the amount of fittings
and other hardware. In this design, the amount of hardware was reduced to a coupling, a cap and
two washers. The reduction in fittings and hardware also reduced the weight and cost of the
fittings. The reduction in weight was an important factor because it meant that the float needed
less buoyant force in order to operate, which in turn means a lower price for the foam. With all
these benefits this still was not the final design.
Figure 18- Design tool model of the “continuous rod” design
The final preliminary design was similar to the “continuous rod” model. The design is
identical in every aspect, except for the shape of the float. Instead of a cylinder, it was decided
to make the float into a block shape. The reasoning behind this change is the material’s stock
geometry. An example of this design decision is evident in the geometry chosen for the original
float. The stainless float was built in the shape of a cylinder because the rough material was a
25. pipe. This meant that minimal machining was required to make a cylindrical float. Additionally,
the cylindrical design helped the stainless steel float to combat the pressurized environment of
the FWKO.
Foam’s rough stock, however, is a sheet. This meant that it was cheaper to cut blocks
from the sheets as oppose to cutting blocks and machining them into a cylinder. It was also more
efficient, resulting in less volume loss from the machining process, which resulted in a lower
bulk unit price. Another reason is that foam does not need to be in a pressure resistant shape.
This is because it is the closed-cell nature of the foam that provides resistance to pressure, not the
geometry. After the third design was created it was time to assess the plan with the design tool,
by hand, and the facilities engineer, Alan Duell
The assessment of the final design was broken into three tiers. The first tier was
checking the design tools calculations by hand to catch any lingering or potential errors. The
second tier was to determine if the design would perform in the variety of environments possible
in the FWKO. The final tier of assessment was a peer review by the Waynoka field office
facilities engineer, Alan Duell.
The first tier of assessment of the new design was hand checking all the design tool
calculations. This step was done to ensure that there were no errors in the design tool that would
cause a failure in the design. These calculations were done in steps, comparing each part of the
calculation to the code of the design tool. During this process active and potential errors were
fixed in the design tool. The eventual result of this assessment was that the hand calculations
matched the design tool, which meant that there were most likely no errors in the tool or the
design.
The second tier of assessment was the design tool. The design tool helped determine if
the proposed design had enough torque available to meet the torque requirements of the dump
valve. Second, the tool would determine if the float would work in oil and water, as well as
determine if the float would still operate under 250 psi. To test the float in oil and water, two
design files were created. One was to test the float in a produced water environment and the
other file was made to test the float in a light oil environment.
The test for volume reduction due to pressure was determined using the compression
modulus of the polyurethane foam, which theorized the foam would lose about 2.5% volume.
For a safety factor, the chosen volume reduction was assumed to be 5%. This means that as the
volume of the float decreased, the density of the buoyant material would increase, making the
float less useful. To test these conditions two additional design files were created in the design
tool. One was created for a float which shrunk and was in the oil side of the FWKO. The other
file was for the situation in which the float had shrunk in the produced water compartment of the
FWKO.
26. The final part of the design tool assessment was to compare the chosen design with the
original design. This was important because, the new design should act similar to the original.
The metrics that were chosen to compare the two designs were: total weight, net upward force
and percent of the float submerged. Once the design passed all the tools requirements, it was
ready for the design to be peer reviewed.
The final design was peer reviewed by the field office facilities engineer. The approach
that he took in reviewing the work was mostly conceptual. The first step was that he wanted me
to walk through every module of code for the design tool. During this process I explained the
purpose of every line of code and the reasoning behind it. The next step in peer review process
was conceptual questioning. The first question was to ask me to draw out a free body diagram of
the float assembly and assign forces and moments to the diagram. The next question was again
to assign forces and moments to a free body diagram, but for the trunnion and dump valve
assembly. After answering Mr. Duell’s conceptual questions and him approving my design, the
final tier of assessment was completed. With this final tier complete, finding manufactures for
the design was the next priority.
27. Figure 19-Picture of the final design with all the parts
Figure 20-Picture of the prototype float assembled
28. Manufacturing
This section will discuss the method, and process that was taken to order a prototype.
The first issue that needed solving was to find a company that could potentially supply and
machine the foam. This ability would keep the supply chain for the new design short and
manageable. After some researching, the company General Plastics was found which could
supply, and machine the foam into the block shapes needed. With this problem solved, all that
was needed was a source for the pipe, fittings and other hardware.
Fortunately the answer to this problem was simple as Chesapeake Energy has a service
company supply all their piping, and hardware. After being informed of this, all that was
required was an email of the needed materials. With sources for material and machining
established, all that remained was to perform an economic analysis and test the float in the
FWKO.
Economic Analysis
The point of this economic analysis was to demonstrate through the use of engineering
economic analysis which conditions the foam float required to be profitable and how large this
profit would be. These conditions were directly related to the lifespan of both types of floats and
the Minimum Attractive Rate of Return (MAR). This part of the report will also cover the many
challenges that were overcome in order to compile the analysis. The first challenge was the
choice of which analysis method to use, Present Worth (PW) or Equivalent Uniform Annual
Worth (EUAW)? This challenge was then followed by figuring out the unknowns in the
economic analysis; like MARR, lifetimes, and how to relay the pertinent information once the
analysis was complete.
As stated in the previous section, the first problem was which method to use. Very
quickly the field narrowed to two ideas, the PW or the EUAW method. The first method, PW
analysis, is a very basic analysis. The analyst looks at the costs attributed to a piece of
equipment over its lifespan, then it is compared with another piece of equipment’s costs. If the
lifetimes are different, then the analyst examines the least common multiple of the two
machines’ lifetimes. Then all the costs, annual and one-time, are converted into one present day
cost/benefit using the principle of the time value of money. This principle captures the reality
that a dollar today is worth more than a dollar tomorrow because of the interest today’s dollar
receives.
For simple analysis the PW method is quite capable and easy to use, but in the case of
this project there was one difficulty; the lifetimes of both the foam and the stainless float were
unknown. Even if these lifetimes were known, the math operations could have become
complicated depending on the least common multiple of the two lifespans. So even though this
method had an advantage by showing savings in today’s dollars, the complicated operations
made the method unusable.
29. The next method that was examined was the EUAW method. This method also uses the
principle of time value of money to make its comparison. The large difference is that this
method converts a one-time payment into a series of payments that can be repeated as long as
necessary. After both options are converted these series are compared to find the best
alternative. This takes the need to find the least common multiple of lifetime away and makes
the calculations much simpler. The only downside to this method was that the resulting
savings/costs are on an annual basis. This is not preferable because the results would be easier to
comprehend as a one-time savings today, not a series of savings every year. Because the EUAW
method was much simpler, it was decided to use this as the method of analysis. Although the
analysis method was found, the unknown variables still needed to be addressed.
The most important unknown during the economic analysis was the unidentified lifetimes
of either floats. This lack of knowledge was mainly because Chesapeake Energy had only
recently changed over to the stainless floats and had not yet started to see wide spread failures.
The lifespan of the foam floats could only be guessed at since they had yet to be tested.
To determine the lifetimes of the floats, internet sources were used to find values that
could be used in a calculations or for an estimate. One important document found that there was
a loss of .1 millimeters per year (mpy) in a sodium chloride solution (The International Nickel
Company, Inc. 13). Taking the thickness of the stainless steel float to be 3.41 millimeters, it
would take about 34 years for the steel pipe to corrode. Another document as well as anecdotal
evidence referred to the welds as even more vulnerable places for corrosion and failure . Taking
all these factors into account, it was decided that the stainless float was most likely to fail
between 5 and 10 years, but it was assumed that the floats would fail closer to 5 years. For the
foam float, no concrete corrosion information could be found, but some documents containing
the general reactivity of polyurethane were found (TerraThane; De Neef). Additionally Alan
Duell and I poured some gasoline on the foam in order to determine if there was any immediate
affect from exposure to hydrocarbons.
Figure 21-Alan Duell and I exposed the foam to gasoline
30. The next unknown to define was the MARR. This number is the interest rate used in the
economic analysis equations and represents the return the money could have received if it had
not been spent. For this project, it would be assumed that any money saved by the
implementation of the foam float would be reinvested within the company. In order to find this
value, other personnel within Chesapeake were contacted for their opinions. After discussing the
rate of return of projects within Chesapeake Energy, the MARR was chosen to be 25%. Now
that the lifespan ranges as well as the MARR had been defined, the analysis would be carried
out.
To solve the problem of the missing lifetime information of each type of float a new
analysis procedure was developed. Instead of calculating every permutation of lifespans, which
would have been impossible to complete, tables were used. These tables have the range of
stainless steel float lifespans for the columns, and the range for the foam float lifespans on the
rows. Using the formula feature in Microsoft Excel, tables of the EUAW values at a 25%, 35%
and 45% MARR were generated (Appendix: Economic Analysis). From these tables, contour
graphs were generated (Appendix: Economic Analysis) so the data could be easily
comprehended. What was gleaned from these graphs was that at 25% MARR, the foam float has
to last a minimum of 1.25 years to be economical, assuming a 5 year lifespan for the stainless
floats. Additionally, this graph shows all other lifespan circumstances the float is economical at.
This is shown by the positive gray, yellow and blue regions in the graph.
Testing
This part will explain the testing procedure and the experiment’s goal values. The
outcome of the experiment will not be covered, as the internship was completed before the
conclusion of the test. The principles behind the procedure will be discussed first, followed by
the explanation of the testing procedure. Lastly, the goal values and recommendations will be
discussed.
The principles behind the testing procedure are easily understood. The testing procedure
relies on the float’s relationship between weight and buoyancy. The procedure takes into
account that any reaction of the float with the FWKO environment will add or subtract mass.
This extra/missing mass will then effect the floats weight and the torque available to activate the
dump valve. This process can be utilized to find a degradation rate of the float. This is done by
comparing the float’s dimensions and weight before install, to the same properties after removal
at a specified period of time. To determine the loss of torque, the design tool will be utilized by
inputting the floats old and new properties to compare designs. These torque values can then be
used to find the rate of degradation and approximately when the float will cease to operate. The
next few paragraphs will cover the procedure steps.
The first step in the procedure is to measure the dimensions and weight of the floats
components before installation. These values are then inputted into the design tool to determine
the designs starting torque. This value is required in order to compare to the float when it is
31. taken out of the FWKO after 6 months. Second, the float is installed and is monitored for six
months for any obvious external signs that the float is not operating, such as no dump valve
activation or inconsistent dump valve operation. Then after 6 months, the float will be removed
and the dimensions and weight of each component will be measured. These measurements will
then be inputted into the design tool to determine the new available torque for the float. The
following step is to again install the float for another six months. This step is to determine if the
changes to the float was just due to pressure, meaning it will degrade no further, or continuous,
which means the float will eventually fail. After another six month period, the float components
will be measured, weighed and the values will be inputted into the design tool. With three test
incidences the values will be plotted to determine the rate of degradation of the float. Once this
rate has been determined it will then be used to calculate the approximate lifespan of the float.
This lifespan can then be compared to the EUAW tables (Appendix: Economic Analysis) to
determine if the float will be economical or not. Even though the EUAW and PC tables will tell
if the float will be economical there were some recommendations about the results that were
made.
The first recommendation that was made is that if the lifespan is predicted to be 5 years,
the float will always be economical at a 25% MARR and under any lifespan of the stainless steel
float; thus the foam float is guaranteed successful if the lifespan is longer than 5 years. The last
recommendation that was made for the testing, is that if the float is uneconomical, but is very
close to being so, it might be worth considering a coating of some sort. These coatings are not
very expensive and could substantially increase the lifespan of the float. Even if these
recommendations are not followed, this testing procedure will be able to give the field engineers
at the Waynoka field office enough information to determine the viability of the foam float.
Conclusion
In review, the foam float was developed to combat the harsh environments of the FWKO
and be cheaper than the current alternative. First the constraints and other considerations were
examined to show what was necessary in order to complete the task of designing a float. The
next step was to program a design tool which could then be utilized to examine a selection of
preliminary designs. These designs continued until the final model was decided upon. What
followed was a three-tiered approach to error check the design tool and the float design. After
the checking was complete a prototype was manufactured. Subsequently, the economic analysis
was carried out; combining both the EUAW and PW approaches to determine the present worth
savings/costs of the foam option. The final part of the design process was the development of a
testing procedure for the field engineers to use, since the internship was completed before the test
would be.
In conclusion, there is no way to know how the foam float will perform. There is both
evidence to show that the stainless floats have a limited lifespan and that polyurethane is
reasonably non-reactive to the FWKO environments. This is the reason for the test that is being
32. conducted, which will help settle these questions and assumptions. The final point to make is
that with the testing procedure and design tool left behind, the personnel at the Waynoka field
office have the tools to both determine the viability of the foam float and the potential of better
float designs.
Academic Relevance
The academic relevance of my internship can be divided into five major categories:
material science, thermodynamics, statics & solids, economic analysis, and safety. This part of
the report will explain how my experience in the field directly related to these categories of the
mechanical engineering program at Texas Tech University.
The first way the internship at Chesapeake Energy related to my schoolwork at Texas
Tech was through material science. The first way this was shown in the field was through the
salt water disposal system. Without material science, Chesapeake’s whole network of pipelines
and disposals would be impractically expensive. It is because of resistant materials such as
plexiglass, polymers and stainless steels that water can be efficiently gathered and disposed of.
The second way that materials science was used in my internship was in my project. It was
because of the knowledge that I learned from Prof. Gray that I was able to design a float that
could stand up to the pressure and corrosion of the FWKO. In reality, many decisions in the oil
field are heavily influenced by material science and how it can help prevent corrosion.
Secondly, thermodynamics also gave me an insight that turned out to be valuable during
my time in the field. As a part of my internship I attended a short course on the workings of
compressors. Principles like compression, expansion, heat exchanging and intercooling all
helped me understand the operation of the compressors utilized in the field. I really enjoyed
learning about the pieces of equipment that, in thermodynamics, was represented by a simple
box. My thermodynamics knowledge also helped me understand the operation of some of the
oilfield equipment; such as heater treaters and measurement valves. In contrast though, the
experience that I gained this summer also helped reinforce my knowledge and give me more
examples that will be helpful in Thermodynamics II in the fall.
Another set of knowledge that came in helpful during my time at Chesapeake was statics
and solids. This class specifically helped me understand how to design my final project. Statics
helped me understand the relationship between the changing angle and the resulting torque.
Without this understanding, it would have been very difficult to design a proper replacement.
Solids was also very integral in my project’s design, by giving me the proper tools to model the
inevitable shrinking of the foam over time. My project was also helped out by the use of
economic analysis.
With the economic analysis skills and approaches I learned at Texas Tech, I was able to
easily approach the problem of the unknown lifespans and MARR to create an accurate
33. economic analysis. In addition to being equipped to properly approach the problem, I was also
able to give an accurate prediction of the savings of my foam float alternative.
Finally, the emphasis on safety was very academically relevant. The safety culture at
Chesapeake was useful because as I approach my senior year, I will be doing more projects in
the departments shop. With the culture that Chesapeake encourages, I’ll be better able to
complete my tasks in the shop safely and in a timely manner. Also, safety is a skill that affects
more than just my academics. Some of the skills, such as a company defensive driving course I
took, will keep me safe during everyday situations and in my future career.
In conclusion, this internship allowed me to use many of the skills that I have learned
thus far in the Texas Tech mechanical engineering program. The internship also reinforced
much of the teaching that I have received during my time at Tech and I look forward to more
internship opportunities in order to make myself a better student and future employee.
34. Works Cited
ASM International. "Basic Understanding of Weld Corrosion." 2006. ASM International. PDF.
July 2016.
Chesapeake Energy. "Corporate Fact Sheet." June 2016. CHK.com. PDF. August 2016.
—. "Corporate Logo." 2016. Image.
—. "Operations Map." 2015. Image.
De Neef. "Chemical Resistance of Polyurethane Foams." n.d. GCP Applied Technologies.
September 2016.
Dreco Energy Services. "Drilling Rig Diagram." n.d.
Gooch, T.G. "Corrosion Behavior in Stainless Steels." 1996. American Welding Society. PDF.
September 2016.
Institute of Gas Technology. Natural Gas in Nontechnical Language. Tulsa: PennWell Corp.,
1999.
Kimray. Valve Sizing. 2016. August 2016.
Ratern, Rick von. "E&P Defining Series." n.d. Schlumberger. Image. 30 7 2016.
TerraThane. "Polyurethane Chemical Resistance Chart." n.d. NCFI. PDF. September 2016.
The International Nickel Company, Inc. "Corrosion Resistance of the Austenitic Chromium-
Nickel Stainless Steels in Chemical Environments." 1963. Nickel Institute. PDF.
September 2016.
35.
36. Appendix
Design Tool
This is a screenshot from the design tool that was programmed in order to design FWKO floats.
37. Manufacturing
This is the first page of the properties given for the polyurethane foam by General Plastics. This
page goes over the functionality and durability of their product
38. This is the second page of the properties given for the polyurethane foam by General Plastics.
This page gives very specific property values for the foam that Chesapeake purchased from
General Plastics (R-3312). Using the compression modulus given on this sheet I was able to
estimate the volume loss due to pressure.
39. This page shows the prototype and bulk pricing for the foam from General Plastics
40. This page shows the bulk pricing for the hardware required for the polyurethane FWKO float
