Drilling Engineering AssignmentMaria Mappouridou

12/29/2013

Question 1

Describe the process of selecting a drilling unit for drilling a well in a water depth of 100m.

In the process of well planning and drilling unit selection, several parameters need to be taken under account for a project to have technical and commercial feasibility together with associated safety and environmental considerations.Thus, several assumptions where made and will be stated below.

Once preliminary geophysical investigations indicate the potential for hydrocarbons several major activities, which may overlap, are required to recover these hydrocarbons from below the seabed.

In general activities and data that need to be taken under consideration are described below:

A target zone is specified and an accurate picture of the subsurface is given by the geologists Fluid distribution (petrophysicists), prognosis of pressures along the planned well trajectory

(reservoir engineers) Transport and Logistics: How far from shore is the target zone? Are there any other platforms

(production or exploration) in the area? How long is this drilling unit will be staying at location? Climate and Geography: What are the weather conditions of the location (extreme winds-

Ice)? Is our location inside of an environmental protected area? What is the depth of the target? Type of drilling rig to be used for the well Proposed location of the drilling rig Hole sizes and depths Drilling fluid specifications Directional drilling information Well control equipment procedures Bits and hydraulics program Cost of drilling Permits required before drilling

Type of Drilling Rig

Rigs are selected based on cost and availability, water depth, drilling depth, their ability to operate safely in expected weather conditions, their capacity to provide power adequate for drilling activities, enough space on board to store the casings and pipes and drilling cuttings.

For the purposes of this exercise we have:

Data: Water Depth (WD): 100m

Assumptions: a. North Sea weather conditions: Average air temperatures vary in January from 0 to 4 °C and in

July from 13 to 18 °C. Winters are stormy and gales are frequent. Tidal ranges average between 4 and 6 meters along the coasts of Britain and in the southern estuaries, while the range to the north and east is less than 3 meters. [1][2]

b. Other factors like drilling depth, mud volume, soil conditions, bulk volume etc. are not taken under account.

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c. Unlimited availability of rigs.

If we limit our selection criteria to WD and environmental conditions as described above we can conclude that both Jack-up rigs and semisubmersible rigs are adequate for drilling.

Jack-up rigs are mobile, self elevating drilling platforms equipped with tubular structure legs that are lowered to the sea floor. Tugboats tow a jack-up to the drill site as a vessel, with its hull riding the sea and its legs raised. At the drill-site, the legs are lowered until they rest on the seabed and jacking continues until the hull is elevated above the surface of the water. Drilling operations can then begin. When they are completed, the hull is lowered until it rests in the water, the legs are raised and the rig can be relocated to another drill-site. There are two basic types of jack-ups, the independent-leg type, usually three legs with lattice construction, and the mat type, in which the legs are attached to a very large mat that rests on the ocean bottom. Both types of jack-ups have a hull, float onto location, jack the legs to the ocean bottom, and then jack the hull out of the water.Semi-submersible rigs consist of a deck containing the working areas and equipment and the living quarters, supported by a hull made up of vertical columns connected to horizontal pontoons. Such rigs operate on a “semi-submerged” position with the lower hull ballasted down below the waterline. Anchored over a wellhead location in this position, the rig provides a stable platform for drilling, due in part to its wave transparency characteristics at the water line. Additionally in the case of a dynamically-positioned (DP) semisubmersible, the rig keeps station over the wellhead location by means of a computer controlled thruster system. [3][4]

ComparisonRig Type Water Depth (m) Environmental ConditionsJack-up 15-150 New technology provides safe operations in harsh

environments.Semisubmersible(Anchored)

80-1800 Preferred in harsh environmental conditions (wave transparency characteristics)

[5][6][7][8]

In order to reach to a final decision we need to examine the drilling costs for both cases. Again we have to assume (assumption e.) that the drilling contract that we will sign with the Contractor will be the same in both cases differing only in “Day Rates”.

ComparisonRig Type Average Day Rate ($)Semisubmersible(<457m)

294,000

Jack-up IC(>91m)

165,000

Jack-up IS(>91m)

95,000

[9]

Although many assumptions have been made based on the three parameters taken into account-water depth, environmental conditions, cost- we can conclude that if no special requirements have a major impact on the well plan a jack-up rig is the best option in our case.

Process for drilling for a dry hole completion

The drilling derrick tower above the drill floor is where most of the activity is concentrated. The derrick supports the weight of the drill string which is screwed together from 9-metre lengths of drill pipe.

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Hoisting equipment in the derrick can raise or lower the drill string. At the bottom of the drill string is a drill bit, which can vary in size and type. It is attached to the drill collars, heavy pipe-sections that put weight on the bit. The drill bit is rotated either by turning the whole drill string ("rotary drilling") or by using a down hole turbine which rotates as drilling fluid is pumped through it. In rotary drilling, the rotary motion is imparted to the drill string by the "top drive". This is an electro-hydraulic motor suspended in the top of the derrick. It is attached to the top of the drill string and imparts torque to it, causing it to rotate. To add a new section of drill pipe the drill string is clamped in the drill floor with wedges (slips) and the top drive disconnected. The new joint is screwed into the drill string suspended in the drill floor, the top drive connected to the top of the new joint, and drilling restarted. The raising and lowering of the top drive and the maintenance of correct tension on the drill string is controlled by the driller operating the draw works lever in a control cabin (called the "doghouse") on the drill floor. Drilling fluid (also called "mud"), which is mainly water-based, is pumped continuously down the drill string while drilling. It lubricates the drilling tools, washes up rock cuttings and most importantly, balances the pressure of fluids in the rock formations below to prevent blowouts. In offshore drilling, the first step is to put down a wide-diameter conductor pipe into the seabed to guide the drilling and contain the drilling fluid. As drilling continues, completed sections of the well are cased with steel pipe cemented into place. A blowout preventer is attached to the top of the casing. This is a stack of hydraulic rams which can close off the well instantly if back pressure (a kick) develops from invading oil, gas or water. A typical problem faced while drilling is the drill string sticking in difficult rock formations such as the thick Tertiary clays in the North Sea. A hydraulic device known as a jar, mounted between the drill collars, can give the drill string a series of jolts. If that does not work, other techniques may be used, including spotting with oil and water. Special fishing tools can also retrieve stuck pipe and broken equipment (junk). Drilling grinds up the rock into tea-leaf-sized cuttings which are brought to the surface by the drilling mud. The drilling mud is passed over a shale shaker which sieves out the cuttings. Oil entrapped in the mud is detected by its fluorescence in UV light. Gas is extracted from the mud in a gas trap and sent under vacuum to a gas detector and analyzer. An increase in the amount triggers an alarm to alert the mud logger and the drilling superintendent. If laboratory tests are needed on potential reservoir rock, a solid core of rock can be drilled by a special hollow drilling bit. Each short length of core retrieved calls for the entire drill string to be pulled out of the well and then reinserted, so coring is an expensive operation. Vital information on the type of rock drilled and the fluids it contains often needs to be obtained either while actually drilling, or after drilling before running casing. This is obtained by running electronic measuring devices into the well - either while drilling (as part of the drill string) or after drilling on "wireline". The various types of measurement include: (1) electrical resistivity of fluids within the rock; (2) the speed of sound through the rock; (3) reaction of the rock to gamma ray bombardment; (4) production of gamma rays from fluids within the rock due to neutron bombardment; and (5) natural gamma radiation of the rocks. The data obtained give indications of rock type and porosity and the presence of oil or gas. Other devices measure hole diameter, dip of strata and the direction of the hole. Sidewall corers which punch or drill out small cores of rock, geophones for well velocity surveys and seismic profiling are also lowered into uncased wells. In deviated wells approaching the horizontal, flexible high-pressure steel coiled tubing may be used to carry wireline logging tools and for performing wellbore maintenance operations.

If oil or gas has been detected in a well, a tool is lowered on a wireline to measure fluid pressures and collect small samples. If the flow rate of the well needs to be measured, a "well test" is carried out. This involves running production tubing with flow control valves and isolation packers into the well, then flowing the hydrocarbons to surface through the high pressure pipe work. At the reservoir level, there are two types of completion methods used on wells: open-hole or cased-hole completions. An open-hole completion refers to a well that is drilled to the top of the hydrocarbon reservoir. The well is then cased at this level, and left open at the bottom. Also known as “top sets” and “barefoot” completions, open-hole completions are used to reduce the cost of casing where the reservoir is solid and well known. Cased-hole completions require casing to be run into the reservoir. In order to achieve production, the casing and cement are perforated to allow the hydrocarbons to enter the wellstream. This process involves running a perforation gun and a reservoir locating device into the wellborne, many times via a wireline, slick line or coiled tubing. Once the reservoir level has been reached, the gun then shoots holes in the sides of the well to allow the hydrocarbons to enter the wellstream. The perforations can either be accomplished via firing bullets into the sides of the casing or by discharging jets, or shaped charges into the casing. While the perforation locations have been previously defined by drilling logs, those intervals cannot be easily located through the casing and cement. To overcome this challenge a gamma ray-collar correlation log is typically implemented to correlate with the initial log run on the well and define the locations where perforation is required.

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Some wells require filtration systems in order to keep the wellstream clear of sand. In addition to running a casing with a liner, gravel packing is used to prevent sand from entering the wellstream. More complicated than cementing a well, gravel packing requires a slurry of appropriately sized pieces of coarse sand, or gravel, to be pumped into the well between the slotted liner of the casing and the sides of the wellborne. The wire screens of the liner and the gravel pack work together to filter out the sand that might have otherwise entered the wellstream with the hydrocarbons. In the last step in completing a well, a wellhead is installed at the surface of the well, often called production tree or Christmas tree. This wellhead device includes casing heads and a tubing head combined to provide surface control of the subsurface conditions of the well. Offshore wells can be completed by two different types of trees: Dry and Wet trees. Dry trees are installed above the water’s surface on the deck of a platform or facility and are attached to the well below the water. Wet trees are installed on the seabed and encased in a solid steel box to protect the valves and gages from the elements. The subsea wet tree is then connected via electronic or hydraulic settings that can be manipulated from the surface or via ROVs. Additionally, wells may have production flowing from multiple reservoir levels. These wells require multiple completions, which keep the production separate. Double-wing trees are installed on multiple reservoir levels. Furthermore, completions have evolved to incorporate downhole sensors that measure flow properties, such as rate, pressure and gas to oil ratio. And they are known as intelligent wells or smart wells. [10][11][12]

Main well controls

The first line of defense in well control is to have sufficient drilling fluid pressure in the well hole. During drilling, underground fluids such as gas, water, or oil under pressure (the formation pressure) opposes the drilling fluid pressure (mud pressure). If the formation pressure is greater than the mud pressure, we have a “kick” (flow of formation fluids into the well) and there is a possibility of a blowout. A kick is controlled (or the well “killed”) when all the formation fluids which entered the wellbore have been circulated out and when the mud in the hole when the kick was taken has been replaced by a mud which exerts a hydrostatic pressure slightly higher than the formation pressure. Mud pressure must, at all times, be slightly higher than the formation pressure and is mainly controlled by the fluid’s density (the mud density changes to withstand the hydrostatic pressure of the formation, as drilling progresses in various depths). To change the mud’s density we use various additives, barite being the most common. Formation and mud pressures are calculated periodically during the drilling process and of course a prognosis of pressures is given before drilling starts.

https://www.osha.gov/SLTC/etools/oilandgas/images/kickback_final.gif

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If, however, the formation fluids that enter a well cannot be controlled with the method described above, there is a serious possibility of a blowout. For this reason Blowout Preventers (BOPs) are always installed on the surface of the well. BOPs are large valves which quickly shut off the well as a last-ditch precaution to prevent a kick from becoming a blowout. Often, Different types of BOPs are used in an arrangement configuration, called a “BOP stack”.There are two main types of BOPs: annular preventers and ram preventers. Ram preventers move two opposing rods horizontally across the top of the well. Ram blocks on the ends of the shafts create a seal around the pipe. Ram blocks come in various sizes and designs to cope with specific drilling operations. Annular preventers use an elastomer packer squeezed across the annulus in an upward-and-inward motion to cork the well and prevent upward movement in the wellbore. Annular preventers are usually the preventer of choice because the packer will form a seal around any diameter tubular or wire line that may be in the well at the time a kick is taken. However, both types are usually employed in stacks. There must be two locations from which the BOPs can be operated: one near the driller’s position and the other outside the security zone or classified area. On land or on a fixed offshore platform, back-up methods for emergency closure may be provided (manual control or hydraulic control using the rig pumps). On a floating vessel there must be complete redundancy of the control equipment. An acoustic control system may also be installed in case of failure of the two principal control systems. The hydraulic accumulators will be located outside the security zone or classified area and must be capable of closing the BOPs as quickly as required. This requirement has lead manufacturers to consider mounting the accumulators on the BOP stack for deep water applications. The accumulator capacity must be such that in the case of a complete power failure the volume of fluid stored at the maximum operating pressure is sufficient to close and reopen all the preventers. The control system must include a pressure regulator, particularly for the control of the annular preventer or a diverter during stripping operations. The pumps used must be capable of fully recharging the accumulators in 10-20 min and they should be able to operate with different energy sources (e.g. electricity and air).[13]

[14][15]

BOP StackUS Dept. of Labor, Occupational Safety &   Health Administration

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Drilling plan. Factors to be considered for safe drilling activity, to the right place.

The drilling plan provides the information necessary to ensure that drilling is conducted with appropriate regard for protection of public health and safety, the environment, correlative rights and maximum economic recovery of hydrocarbons. Furthermore, the drilling plan should attempt to answer the questions that might arise during review. A drilling plan should include a complete description of the proposal and anticipated drilling conditions such as loss circulation, high pressure, and hydrogen sulfide.

Drilling plan components:

Formation TopsIdentification of important geologic markers.

Depth to Oil, Gas, Water and MineralsList of the zones that might bear these resources, plans for protecting such resources, identify salt water zones as they would affect drilling conditions.

Pressure Control (BOP)Size, rating, configuration and testing. Schematic diagrams. Description of any ancillary equipment such as rotating head, remote kill line, mud-gas separator.

CasingSize, weight, grade, thread & coupling, depth and condition. The design criteria, loading assumptions, safety factors used and published specifications should be included. Liner top and lap length should be included and any unusual design conditions should be described.

CementDescription of the amount, type of cement (including additives) for each slurry. Density and yield should also be included.

Circulating MediumType and characteristics of mud for each section of hole and description of standby mud. Air drilling equipment (blooie line, dust suppression equipment, gas ignition source compression equipment size and location on the pad layout relative to the well bore and other equipment) should be included.

Testing, Coring, LoggingGeneral description of the logging suite and if drill stem tests are anticipated then they should be identified.

Pressures, Temperatures, H2SBottom hole pressure should be listed and should correspond to the casing design, to blow-out prevention equipment, and to mud weight. Any up-hole high pressure zones or loss circulation zones and if hydrogen sulfide is anticipated should be identified.

Other AspectsThe final portion of the drilling plan is any other facet of the proposal that might aid in the understanding of what's being proposed, particularly directional or horizontal wells. It should include design, plan view, vertical section and measured and true vertical depths.

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Question 2

Are the costs submitted by the drilling contractor sufficient to enable the company to apply for the three licenses?

Dry hole costs:Well 1=£27.450.000Well 2=£10.000.000Well 3=£11.100.000

Company Market Cap=£25.000.000

Condition for 3 licenses: MC should cover 100% of most expensive well and 50% of the other wells.

MC Need=£[(1x27.450.000)+(0.50x10.000.000)+(0.50x11.100.000)]=£38.000.000

Therefore, the company cannot apply for the 3 licenses since it is £13.000.000 short.

Ways for cost reduction considering data given in Kells environmental statement report

1. Using Kells as an analogue we can estimate the days needed for drilling and running the casing for the first well since they have similar depths (well1 at 13800ft, kells at 15055ft)

Spud to TD Days Spud to TD Cost (£)Well1 49,5 22,900,000kells 33,5 15,497,979

Cost Reduction 7,402,021(Detailed Analysis in Appendix 1)

Although wells 2 and 3 cannot be compared with kells’ wells because of the difference in drilling depths we can discuss with the contractor the possibility of decreasing the total drilling days since it seems that for well 1, drilling days can be reduced significantly.

2. We have a water depth of 452ft in Kells were as in our cases we have a water depth of 308ft (well1) and 300ft (in wells 2and 3 respectively). It is safe to assume that instead of a semisubmersible, a jack-up rig could be used for the 3 wells.

If a jack-up is used cost is reduced even more:

Cost Reduction (£)well 1 (7,402,021 + 1,400,000) = 8,802,021 well 2 1,242,000well 3 1,472,000

Cost Reduction 11,516,021(Detailed Analysis in Appendix 2)

3. The reduction of the following cost figures can also be discussed with the contractor:Days for mobilization/demobilization Days and number of tugboats usedStandby and supply vessel rate (how many trips/week are scheduled?)

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4. The budgetary cost estimates that were given by the contractor are not subject to any kind of contract. The type of contract to be finally used would probably change the final cost for the drilling. For example, in a Turnkey contract, the contractor is responsible to submit documents for permits and receive approvals on behalf of the operator, but these expenses are not included in UKCS requirements.

Define the main parameters that made the cost reduced and explain your approach

Rig cost (rates) and drilling costs are the main factors that define the cost for a well’s dry hole completion. Therefore, a significant cost reduction can be achieved – within the restrictions of regulations – if these costs are limited. In my opinion no other costs could be quantified with the data provided. For example we know that 3 tow vessels are required with a rate of £15,000 per boat per day but we cannot estimate the total tow cost as we do not know how many days the rig would be towed.

Is it possible for the company to apply for the licensing round based on the new data?

In order for the company to be able to apply for the 3 licenses the reduction of the costs not quantified above should cover the remaining amount of approximately £1,500,000. This could be possible considering that drilling days for wells 2 and 3 would also be reduced.

Question 3

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At what point in time would you have suggested that the bit be pulled and why?

In real time analysis the decision to pull the bit should be based on the performance of the bit over a period of time, thus, the bit should be pulled when the cost per foot of the bit run has reached its minimum.

For our data:

Cost per foot=[Bit cost+(Trip time + Time on Bottom)*Rig Rate]/Footage Drilled

             

             Time on Bottom (hrs)

Footage Drilled (ft)

Bit Cost (￡)

Trip Time (hrs)

Rig Rate (￡/hr)

Cost per foot (￡/hr)

 

1 34 1200 8 400141,176470

6  

2 62 1200 8 40083,8709677

4  

3 86 1200 8 40065,1162790

7  

4 110 1200 8 40054,5454545

5  

5 126 1200 8 40050,7936507

9  

6 154 1200 8 40044,1558441

6  

7 180 1200 8 400 40  

8 210 1200 8 40036,1904761

9  

9 216 1200 8 40037,0370370

4  

10 226 1200 8 40037,1681415

9  

11 234 1200 8 40037,6068376

1  

12 240 1200 8 40038,3333333

3  

10

1 2 3 4 5 6 7 8 9 10 11 120

20406080

100120140160

Bit Run Cost

Time on Bottom (hrs)

Cost per foot (￡ /hr)

Calculations and diagram show that after 8 hours cost per foot has a minimum and its starting to increase. Therefore we have a strong indication to pull the bit at this point. However, before the final decision other factors should be taken under consideration. For example, if the bit entered a new type of formation its performance might be affected. Question 4

Plot Pore Pressure-Depth information

Pressure (psi)

Depth Below Drillfloor (ft)

0  0

465 1000

2325 5000

3720 8000

6800 8500

6850 9000

6900 9500

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0 465 2325 3720 6800 6850 69000

100020003000400050006000700080009000

10000

Pore Pressure Profile

Pressure (psi)

Depth (ft)

Pore Pressure gradients in the formations at 8000ft, 8500ft and 9500ft

Patm + (ðP/ðz)*z = P(z)

Patm (psi)

P(z) (psi)

Depth (ft)

ðP/ðz (psi/ft)

14,7 3720 8000 0,463

14,7 6800 8500 0,798

14,7 6850 9500 0,72

Mudweight (ppg) required to drill the hole section down to 8000ft, 8500ft and 9500ft (Assumption: maximum of 200psi overbalance on the formation pore pressure is required)

Patm + (ðP/ðz)*z = P(z) MW = (P(z) + 200)/(0,052*TVD)Patm (psi)

P(z) (psi)

Depth (ft)

ðP/ðz (psi/ft)

mud weight (ppg)

14,7 3720 8000 0,463 9,423076923

14,7 6800 8500 0,798 15,83710407

14,7 6850 9500 0,72 14,27125506

If the mudweight used to drill down to 800ft were used to drill the formation pressures at 8500ft what would be the over/underbalance on the formation pore pressure at this depth?

P(z) = MW(8000ft)*0,052*8500    

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mud pressure at 8500ft using mud weight at 8000feet (psi)

formation pressure at 8500 feet (psi)

underbalance (psi)

4165 6800 -2635

If the mudweight of 9,42ppg were used to drill at 8500ft the borehole pressure would be 2635psi less than the formation pressure.

Appendix 1

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Kells

15055ft / 3 tug boats / water depth at 452ft

PHASE Days COSTS (￡)

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Drill 36" hole to 784ft 1

15497979,8

Run and cement 30" casing 1,5Drill 26" hole to 3316ft 4Run and cement 20" casing/install and test BOP 5,5Drill 171/2" hole to 7992ft 4Run and cement 133/8" casing 4,5Drill 121/4" hole to 13917ft 4,5Run and cement 95/8" casing and test BOPs 5,5Drill 81/2" hole to 15055ft 3

Spud to TD Days 33,5 ￡15,497,979 Rig mobilization and preparation 4,5 Demobilize rig 3,5

Cost Reduction ￡7,402,021

Assumption made: total cost is equally divided into 49,5 and 33,5 days respectively.

Appendix 2

Rig type Rig Rate Days on Spud to TD Total Rig Cost Rig Cost Spud to TD

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(￡/d) site days (￡) days (￡)well 1 semi 200000 60,5 40,5 12100000 8100000kells semi 200000 33,5 6700000 well 2 semi 200000 22 13,5 4400000 2700000well 3 semi 200000 24,5 16 4900000 3200000 21400000 14000000

Rig typeRig Rate (￡/d)

Days on site

Spud to TD days

Total Rig Cost (￡)

Rig Cost Spud to TD days (￡)

well 1

Jack-up 300"+ 108000 60,5 40,5 6534000 4374000

well 2

Jack-up 300"+ 108000 22 13,5 2376000 1458000

well 3

Jack-up 300"+ 108000 24,5 16 2646000 1728000

(rigzone) 11556000 7560000

References

[1] http://www.britannica.com/EBchecked/topic/419398/North-Sea/33268/Hydrology

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[2] http://en.wikipedia.org/wiki/North_Sea#Major_features

[3] http://www.seadrill.com/drilling_units/fleet_concepts

[4] http://petrowiki.org/PEH%3AOffshore_Drilling_Units#Jackups

[5] http://petrowiki.org/MODU_selection

[6] http://www.onepetro.org/mslib/servlet/onepetropreview?id=00018623&soc=SPE

[7] http://www.maerskdrilling.com/DrillingRigs-2/UHEJ/Pages/ultra-harsh-environment-jack-ups.aspx [8] http://www.petromin.safan.com/mag/pmarapr13/r18.pdf

[9] http://www.rigzone.com/data/dayrates, (20/12/2013)

[10] http://www.oilandgasuk.co.uk/publications/britainsoffshoreoilandgas/Exploration/Drilling.cfm [11] http://www.rigzone.com/training/insight.asp?insight_id=326&c_id=23

[12] http://www.npc.org/Prudent_Development-Topic_Papers/2-11_Subsea_Drilling-Well_Ops- Completions_Paper.pdf

[13]http://books.google.gr/books?id=hI5W8MOWjNAC&pg=PA83&lpg=PA83&dq=well+control+kick+blowout&source=bl&ots=DnB3HX674c&sig=RBAaU2nRlsrn94KXZi2GhvBgFVg&hl=el&sa=X&ei=cpO4UpT0L4nesgb4woGAAQ&ved=0CFgQ6AEwBA#v=onepage&q=well%20control%20kick%20blowout&f=false

[14] https://www.osha.gov/SLTC/etools/oilandgas/drilling/wellcontrol.html

[15] http://www.rigzone.com/training/insight.asp?insight_id=304&c_id=24

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