Texas Tech University

Chesapeake Energy Internship 2016

Field Engineer Internship

Matthew Peter Barten

ENGR 3000

Shannon Younger

September 7, 2016

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

Conclusion ................................................................................................................................ 31

Academic Relevance ................................................................................................................... 32

Works Cited ................................................................................................................................. 34

Appendix ...................................................................................................................................... 36

Design Tool ............................................................................................................................... 36

Manufacturing ........................................................................................................................... 37

Economic Analysis ................................................................................................................... 41

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

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.

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

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

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

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

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

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

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).

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

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

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.

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

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.

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

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

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

𝐶𝑉)

2

𝐺 = 𝑆𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝐺𝑟𝑎𝑣𝑖𝑡𝑦

𝐶𝑣 = 𝑉𝑎𝑙𝑣𝑒 𝐹𝑙𝑜𝑤 𝐶𝑜𝑒𝑓𝑓𝑖𝑒𝑐𝑖𝑒𝑛𝑡

∆𝑃 = 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐷𝑟𝑜𝑝 (psi)

𝑄 = 𝐹𝑙𝑜𝑤 𝑅𝑎𝑡𝑒 (gpm)

Equation 2-Pressure Drop Equation

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

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

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

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

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.

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.

Figure 19-Picture of the final design with all the parts

Figure 20-Picture of the prototype float assembled

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.

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

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

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

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

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.

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.

Appendix

Design Tool

This is a screenshot from the design tool that was programmed in order to design FWKO floats.

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

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.

This page shows the prototype and bulk pricing for the foam from General Plastics

This page shows the bulk pricing for the hardware required for the polyurethane FWKO float

Economic Analysis

These tables show the annual savings/costs of the foam float depending on the lifetime of the

stainless and foam floats. Each table is calculated at a different MARR to better determine the

viability of the float.

0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10

0.5 $486 $139 $24 -$33 -$67 -$89 -$105 -$117 -$126 -$133 -$139 -$143 -$147 -$150 -$153 -$155 -$157 -$159 -$160 -$161

1 $603 $256 $141 $84 $50 $28 $12 $0 -$9 -$16 -$21 -$26 -$30 -$33 -$36 -$38 -$40 -$42 -$43 -$44

1.5 $642 $295 $180 $123 $89 $67 $51 $39 $30 $23 $18 $13 $9 $6 $3 $1 -$1 -$3 -$4 -$5

2 $661 $315 $200 $142 $108 $86 $70 $58 $50 $42 $37 $32 $28 $25 $23 $20 $18 $17 $15 $14

2.5 $673 $326 $211 $154 $120 $98 $82 $70 $61 $54 $48 $44 $40 $37 $34 $32 $30 $28 $27 $26

3 $680 $334 $219 $162 $128 $105 $89 $78 $69 $62 $56 $51 $48 $44 $42 $39 $37 $36 $34 $33

3.5 $686 $339 $224 $167 $133 $110 $95 $83 $74 $67 $61 $57 $53 $50 $47 $45 $43 $41 $40 $38

4 $690 $343 $228 $171 $137 $114 $99 $87 $78 $71 $65 $61 $57 $54 $51 $49 $47 $45 $44 $42

4.5 $693 $346 $231 $174 $140 $117 $102 $90 $81 $74 $68 $64 $60 $57 $54 $52 $50 $48 $47 $45

5 $695 $349 $233 $176 $142 $120 $104 $92 $83 $76 $71 $66 $62 $59 $56 $54 $52 $51 $49 $48

25 % MARRStainless Lifespan

Foam

Lif

esp

an

0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10

0.5 $515 $155 $36 -$23 -$58 -$81 -$96 -$108 -$117 -$124 -$129 -$133 -$137 -$140 -$142 -$144 -$146 -$147 -$148 -$149

1 $637 $277 $158 $99 $64 $41 $25 $14 $5 -$2 -$7 -$12 -$15 -$18 -$20 -$22 -$24 -$25 -$26 -$27

1.5 $677 $317 $198 $139 $104 $82 $66 $54 $45 $38 $33 $29 $25 $22 $20 $18 $16 $15 $14 $13

2 $697 $337 $218 $159 $124 $101 $86 $74 $65 $58 $53 $49 $45 $42 $40 $38 $36 $35 $34 $33

2.5 $709 $349 $230 $171 $136 $113 $97 $86 $77 $70 $65 $60 $57 $54 $52 $50 $48 $47 $46 $45

3 $717 $357 $238 $179 $144 $121 $105 $93 $85 $78 $72 $68 $65 $62 $59 $58 $56 $54 $53 $52

3.5 $722 $362 $243 $184 $149 $126 $110 $99 $90 $83 $78 $74 $70 $67 $65 $63 $61 $60 $59 $58

4 $726 $366 $247 $188 $153 $130 $114 $103 $94 $87 $82 $77 $74 $71 $69 $67 $65 $64 $63 $62

4.5 $729 $369 $250 $191 $156 $133 $117 $106 $97 $90 $85 $80 $77 $74 $72 $70 $68 $67 $66 $65

5 $731 $371 $252 $193 $158 $136 $120 $108 $99 $92 $87 $83 $79 $76 $74 $72 $70 $69 $68 $67

35 % MARRStainless Lifespan

Foam

Lif

esp

an

0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10

0.5 $545 $171 $48 -$12 -$48 -$71 -$87 -$98 -$106 -$113 -$118 -$122 -$125 -$128 -$130 -$131 -$133 -$134 -$135 -$135

1 $671 $297 $174 $114 $79 $56 $40 $28 $20 $13 $8 $4 $1 -$1 -$3 -$5 -$6 -$7 -$8 -$9

1.5 $712 $339 $216 $156 $120 $97 $81 $70 $61 $55 $50 $46 $43 $40 $38 $37 $35 $34 $33 $33

2 $733 $360 $237 $176 $141 $118 $102 $90 $82 $75 $70 $66 $63 $61 $59 $57 $56 $55 $54 $53

2.5 $745 $372 $249 $188 $153 $130 $114 $102 $94 $87 $82 $78 $75 $73 $71 $69 $68 $67 $66 $65

3 $753 $379 $256 $196 $160 $137 $122 $110 $102 $95 $90 $86 $83 $80 $78 $77 $75 $74 $74 $73

3.5 $758 $385 $262 $201 $166 $143 $127 $115 $107 $100 $95 $91 $88 $86 $84 $82 $81 $80 $79 $78

4 $762 $389 $266 $205 $170 $147 $131 $119 $111 $104 $99 $95 $92 $90 $88 $86 $85 $84 $83 $82

4.5 $765 $391 $268 $208 $172 $150 $134 $122 $114 $107 $102 $98 $95 $93 $91 $89 $88 $87 $86 $85

5 $767 $394 $271 $210 $175 $152 $136 $124 $116 $109 $104 $100 $97 $95 $93 $91 $90 $89 $88 $87

45 % MARRStainless Lifespan

Foam

Lif

esp

an

These graphs represent the data of the tables found in the appendix.