Complete Well Design

8/3/2019 Complete Well Design

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ContentsExecutive summary ......................................................................... 2

1. Rig selection ........................................................................... 2

2. Pore pressure and fracture pressure. ......................................... 4

3. Problems that could be encountered during drilling in differentformations. ..................................................................................... 5

4. Casing scheme ........................................................................ 6

5. Mud types. Mud programme ..................................................... 7

6. Functions of cement. Cement programme .................................. 9

7. Maximum hook load .............................................................. 10

8. Safety while drilling ............................................................... 11

9. Well completion .................................................................... 12

Conclusion .................................................................................... 13

Appendix A. Molly field pressure profile, mud weights and casing stringsdepths ......................................................................................... 14

Appendix B. Hook load calculation ................................................... 15

Appendix C. BOP stack working pressure calculation .......................... 16

Appendix D. Downhole completion design ......................................... 17

References.................................................................................... 18

Bibliography .................................................................................. 18


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Executive summary

This report provides a brief description of main steps of well planning

process through the example of an exploratory well in the Molly field in

the North Sea. The main steps include: rig selection, study of pore

pressures, fracture pressures and lithology, construction of casing design,

mud and cement programme, completion design and design of well

control system.

1. Rig selectionThere are many criteria that should be taken into account when selecting

a proper marine rig. This is the list of main criteria:

1. Water depth rating2. Derrick and substructure capacity3. Physical rig size and weight4. Deck load capacity5. Stability in rough weather6. Duration of drilling programme7. Rig rating features, i.e. horsepower, pipe handling capabilities,

mud mixing capacity

8. Exploratory vs. development drilling9. Availability and cost

Water depth rating is usually considered as most important selection

criteria for offshore rigs. For this reason, the selection process of suitable

rig to drill a well in Molly field should be considered in accordance with

this main factor.

Generally, Mobile Offshore Drilling Units are divided into two categories:

floaters and bottom supported. Floaters are located on top of the water

surface or slightly below it. This group includes two types of drilling rigs -

semisubmersibles and drill ships. Bottom-supported rigs, on the other

hand, are contacting the bottom of the sea and are supported by it.


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Most widely used type of marine drilling units is a jackup rig. The largest

jackup rigs are able to drill in locations with water depths up to 400 feet,

while the maximum well depth is around 30,000 feet. (Baker 2001) Deep

platforms are capable of drilling wells in water depths up to 1000 ft, but

their usage is economically justified only for long-term development

drilling. (Adams and Charrier 1985) Semisubmersible rigs are specially

designed vessels for offshore petroleum industry, therefore operation

costs are generally much higher due to large amounts of initial

investment required.

Implementation of a jackup rig for drilling a well in Molly field would be

economically most efficient alternative. The water depth of 160 ft is in

the range of operation of most jackup rigs, thus there is no necessity to

use floating units that are capable to operate in deeper waters. Operation

costs of a jackup rig are much lower and they are more easily available

on the market. From the shallow water depth it can be assumed that

Molly field is located not far from the shore, therefore there is no need to

utilize a drillship capable of carrying large amounts of equipment and

materials required for drilling.


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2. Pore pressure and fracture pressure.Pore pressure.

Formation pressure is one of the most important factors that influences

well design and drilling operations. If formation pressure is not correctly

estimated, it can lead to variety of drilling problems, for instance

blowouts, lost circulation, hole instability, stuck pipe and excessive costs.

However, in zones of abnormal pressures it can be very challenging to

predict formation pressures accurately.

Knowledge of formation pressures is the basis of the whole well planning

process, thus not enough attention paid to formation pressure evaluation

can cause in the other stages of well planning being inadequate.

To predict formation pressure several methods can be implemented. They

can be categorized in three groups:

1.Areal analysis from seismic data

2. Offset well correlationa. log analysisb. drilling parameter evaluationc. production or test data

3. real-time evaluationa. qualitativeb. quantitative (Adams and Charrier 1985)

Fracture pressure

Reliable information on fracture pressure gradient is essential to avoid

problems with lost circulation and selecting a proper casing seat depth. It

becomes even more valuable when drilling in zones of low permeability,

since it is necessary to propagate hydraulic fracturing to increase well

productivity.


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While there are numerous theoretical and field developed equations of

determining the fracture pressure gradient, none of the theoretical

methods can consider all characteristics of the rock formations. For this

reason, testing each new casing seat for fracture pressure to determine

accurate fracture pressure gradient is very common in the field.

Leak-off test is the most widely used direct method for identifying

fracture pressures.

These two parameters are the basis for further well design process,

particularly casing design, as well as planning the drilling mud

programme. Mud weight should always be kept in the window between

pore pressures and fracture pressures of all formations that mud is

affecting. The casing is run to isolate the weaker formations, to use

heavier muds to drill lower formations. These two factors are very

important for the safety of drilling process.

3. Problems that could be encountered duringdrilling in different formations.

Different hazards occur while drilling in different rock formations. Shales

and sandstone formations, which are present in the Molly field have

specific properties that could cause a number of problems that are

discussed further. Most of them can be avoided by implementation of

proper mud control programme.

Lost Circulation

In porous sandstone, gravel formations, vugular limestones or any rock

formation that has faulted, fissured and jointed zones, high permeability

results in drilling fluid flowing into the formations rather than circulating

back up the hole.


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Heaving shale problems

Some shale layers demonstrate high adsorption of water. The reason for

that is the presence of hydratable clays in the formation. It can lead to

the clays swelling and sloughing into the hole and result in further drilling

problems, such as pipe sticking, hole bridging and excessive build-up of

solids in the mud.

The most effective way to deal with this problem is to utilize an inhibitive

mud, which will reduce the hydration rate of the clays.

4. Casing schemeThe casing scheme is based on the consideration of formation and

fracture gradients. However, there are other geological factors that

should be taken into account during selection of casing seat depths.

In the given well there is a number of formations that should be

considered. The surface casing is lowered to 5640 ft below RKB to ensure

that Paleocene lower sands that could contain fresh waters are covered

prior further drilling. It isolates Paleocene middle shales, clays and light

sandstones that could cause heaving and sloughing problems. It also

provides support for the BOP stack.

The production casing is run from the bottom up to the casing hanger on

the surface. It isolates the possible hydrocarbon bearing zone and gives

support to weak and hydratable Jurassic and Triassic formations.

TVD of casing seat, ft Hole size Casing size, OD

984 33" 30"

5640 17 1/2" 13 3/8"

10240 12 1/4" 9 5/8"

Table 1. Casing scheme


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5. Mud types. Mud programmeThere is a large variety of drilling fluids currently exploited in the

industry. Generally, they can be divided into three categories: water, oil

and in some cases gas based fluids. These categories can be subdivided

depending on the different additives used to change the density or

chemical and physical properties of mud.

Water based fluids

Water is the main component and is the continuous phase of the fluid.

Water based muds can be categorized into four groups depending on the

presence or absence of inhibitor and dispersant additives.

Non-dispersed and non-inhibited muds.

Very simple CMC Gel or Spud Gel mud systems, though could be used in

drilling only very unreactive formations.

Dispersed and non-inhibited muds.

Simple clay-based systems. However, because of the problems while

drilling in reactive clay is not commonly used in oil industry.

Dispersed and inhibited systems.

Fresh or sea water based muds made through addition of lime or

gypsum. High level of calcium ions in the solution assists in prevention

borehole instability, clay heaving and sloughing.

Non-dispersed and inhibited systems.

Very widely used mud type, especially in highly reactive clay formations

and while drilling though salt layers. The mechanism of inhibition varies

depending on the inhibition agent.


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Oil based fluids

These muds contain oil as their main component and continuous phase.

Water can be added to the mixture as discontinuous phase, in that case it

is called invert emulsion.

It is beneficial to use this type of mud in water sensitive formations, such

as production zones and shales, since oil doesn't hydrate the shales. They

are also useful in drilling complex geometry wells due to their high

lubricity characteristics. Corrosion resistance, stuck pipe prevention,

contamination are some other factors that make oil based muds relatively

cost effective.

Environmental problems related to the usage of oil based muds led to

development of biodegradable synthetic oil muds. These muds are very

expensive and should be considered only in situations where it is

impossible to drill using water based muds.

TVD, ft Hole size Casing

size

Mud type Mud weight,

ppg

984 33" 30" Sea water/bentonite 10

5640 17 1/2" 13 3/8" Sea water/bentonite 12

Water based mud with inhibition additives is used to prevent clay

hydration and sloughing

10240 12 1/4" 9 5/8" Oil based mud* 13

*Oil based mud is used to reduce formation damage in the potential

reservoir formations and to avoid clay hydration

Table 2. Mud programme

Mud weight graph is provided in Appendix A.


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6. Functions of cement. Cement programmeCement is used for four main reasons:

1.Provides zonal isolation2.Sustains axial load of casing string3.Protects from the corrosive influence of fluids and offers casing

support.

4.Supports the boreholeCementing of the surface casing string will be conducted up to the

surface, since it is providing support to the next string.

Main objectives of this cementing stage are: 1) to provide zonal isolation

of weak formations, i.e. heaving shales, weak sandstones and water

bearing formations; 2) Provide good casing shoe for further drilling with

higher mud density.

A spacer should be run between mud and cement to act as a buffer to

prevent contamination of cement slurry from mud. It also helps in

providing good mud removal and cement bond. The amount of spacer

needed should provide enough annular depth to ensure that no contact

between cement and mud is possible, since mud and cement are

incompatible fluids and contamination could lead to channelling or pre-

mature setting of cement inside the casing

For economical reasons two types of cement slurries will be used: lower

density extended cement slurry for non-critical parts, from 4500 ft up to

the surface, and a higher density cement slurry with better compressive

strength for isolating formations with possible water migration -

Paleocene water sands, 4500 ft-5640 ft.

Cementing of the production casing string will be conductedwith

the same class G cement with high density that provides good

compressive strength and has fluid loss control additives to avoid

dehydration of the cement filtrate to permeable formations. Top of

cement is run only up to the "Piper" sandstones with a safety margin of


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500 ft additional annular length. Accordingly, the top of cement will be at

7000 ft point. Thus, the critical possible hydrocarbon bearing formations

and zones of possible water migration are cased and cemented.

Cementing the production string up to the top should be avoided due to

risk of possible trapped annular pressure. This pressures can represent a

large hazard for casing and tubing. In addition, it is beneficial from the

financial point of view to use smaller amounts of cement.

In this casing section gas migration control additives like latex polymers

should be included in the slurry to prevent gas trapping in the cement

during its thickening period, as it can largely reduce cement's physical

characteristics. Also it is essential to have proper centralisation in this

section to aid in proper mud filter cake removal to get a good cement

bond to casing and formation.

7. Maximum hook loadThe two main loads that have the strongest impact on derrick structure

are the longest drill string configuration and the longest casing string

used. Usually, in most of the modern medium to deep wells the casing

string is much heavier than the drill string. To make an estimate of

derrick capacity weights of both strings will be calculated.

Drill string buoyant weight calculation

Common practice recommends avoiding putting ordinary drill pipes under

compression, since they are only designed to work under tension. For this

reason, it is important to make sure that the total weight of Bottom-hole

assembly in mud is higher than the maximum required weight on bit, so

that the point of zero stress will always be lower than drill pipe to BHA

connection. In practice, it is suggested to decrease the weight on bit

value even further, to less than 85% of the BHA weight. (Rabia)


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In the calculation presented in Appendix B it is shown that the total drill

string weight in mud is equal to lbs. With an additional 150 000

lbs allowance for over pull during tripping operations the maximum hook

load equals to 384 715 lbs.

The total buoyant weight of production casing is

Therefore, the maximum load on the derrick structure is

imposed by casing string and is equal to

8. Safety while drillingBlowouts

Blowouts are the most hazardous problem in drilling operations. They

occur when hydrostatic pressure of mud column becomes lower than

formation pressure. It is obvious that adequate mud weight is the main

method to control this risk, although excessively rapid withdrawal of the

drill string is also commonly overseen as the cause of blowouts. This

phenomenon is described as pipe suction and depends on the speed ofpulling, mud viscosity and gel strength, and hole-pipe clearance.

Therefore, it is important to keep the mud viscosity as low as possible.

For this reason deflocculants are added to the drilling fluid. Velocity of

drill string retraction is also a big concern and must be always kept in

adequate ranges.

However, it is not always possible to predict all regions of abnormal

pressures, so blowouts happening is inevitable in drilling industry. That is

why second barrier in safety deals with mitigation of this risk, through

implementation of a proper well control system. The key equipment used

for this is the blowout prevention stack. They are designed to stop the

flow of fluid through the drill pipes or annulus.

The pressure that impacts the BOP stack is calculated in appendix C and

it is equal to 3848 psi. From the BOP pressure ratings available on the


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market (Burgoyne et al. 1986), we can assume that a 5000 psi working

pressure stack would be suitable for this well.

9. Well completionSince the well drilled has two possible hydrocarbon bearing zones, it is

essential to provide isolation of this zones from each other. This function

is served by packers, which also provide means for downhole tubing

anchoring and casing protection.

For safety reasons, to prevent uncontrollable release of hydrocarbons it is

required to install a safety valve, which acts as a second barrier in well

control system.

To support and secure the tubing string it is necessary to install a tubing

hanger.

Two zones of perforation require installing of selective production

equipment, which will assist in producing only from particular zone, while

shutting off the other. This function is served by sliding sleeves, that are

placed on both perforations.

Installing of hydraulic set packers requires pressure differential between

tubing and annulus. For this reason it is necessary to set the plug in the

nipple. Nipple can be used in many other applications, such as sealing

and locking of different downhole equipment.

Depending on the needs of well operation, there is a variety completionaccessories: chemical injection mandrel - provides ability to inject

chemicals in various applications, e.g. cleaning the well from the scale

and paraffins.

Downhole completion design is provided in Appendix D.

Automatic shutdown system provides another safety barrier to control

different types of blowouts.


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List of installed equipment

1. Tubing Hanger2. Chemical Injection Mandrel3. Gauge Mandrel with the P/T gauge4. TRSSSV5. Sliding sleeve6. Packers7. Nipple8. Automatic shutdown system

Conclusion

All stages of well design process that were described show closeinterconnection between each other. For example, adequate mudprogramme or casing design influences every later stage of the designprocess.

Word count: 2493


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Appendix A. Molly field pressure profile, mud weights and casing strings depths

-12000

-10000

-8000

-6000

-4000

-2000

0

8 9 10 11 12 13 14 15 16 17 18

Depth,

ft

Equivalent mud density, ppg

Pore pressure

Fracture gradient

Trip margin

Safety margin

Mud density

Conductor

Surface

Production


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Appendix B. Hook load calculation

To calculate the weight of drill collars it is necessary to estimate the

maximum required weight on bit, to ensure that weight on bit will always

remain 15% lower than the total weight of drill collars. In the table of

ranges of bit weights and rotary speeds recommended by manufacturers

(Burgoyne et al. 1986) it is suggested to use WOB not more than 6200

lb/in of bit diameter for drill bits, to drill in hard limestones and

dolomites. So, required WOB is

,

after applying the safety factor and buoyancy factor the required weight

of drill collars is

Rabia (198 recommends using drill collars to drill hole sections.

To determine the number of drill collars and their weight, we should

divide the total required weight of DC in mud by its nominal weight per

foot and the length of one drill collar:

.

The total weight of 24 drill collars is

while

the total length is

The drill string is consisting of 5" OD drill pipes with nominal weight of

lbs/ft. Thus, the ( )

( )


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Appendix C. BOP stack working pressure calculation

The pressure that the BOP stack must withstand is equal to the between

the formation pressure and the gas hydrostatic pressure:

Therefore, these parameters should be calculated:

As a result,

This calculation should be used for a worst case scenario, only for shallow

depth wells. Usually, operator's experience suggests using 80% design

factor: (Adams and Charrier 1985)


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Appendix D. Downhole completion design


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References

ADAMS, N.J., CARRIER, T., 1985. Drilling engineering. A complete wellplanning approach. Tulsa, OK: PennWell publishing company.

BAKER, R., 2001.A primer of oilwell drilling: a basic text of oil and gasdrilling. 6th ed. Austin, TX: University of Texas at Austin.

BOURGOYNE, A. T. JR., et al., 1986.Applied drilling engineering.Richardson, TX: First Printing, Society of Petroleum Engineers.

RABIA, H., 1985. Oilwell drilling engineering: principles and practice.London: Graham and Trotman.

Bibliography

ECONOMIDES, M. J., et al., 1998. Petroleum well construction. Hoboken,NJ: John Wiley & Sons.

GATLIN, C., 1960. Petroleum engineering. Drilling and well completions.Englewood Cliffs, NJ: Prentice-Hall, Inc.

HEAVY OIL SCIENCE CENTRE, 2011. Drilling problems and drillingoperations. [online]. Heavy oil science centre. Available from:http://www.lloydminsterheavyoil.com/drilling.htm [Accessed 19November 2011].

SERENE ENERGY, 2010. BHA weight & weight-on-bit. [online]. Aberdeen:

Serene Energy. Available from: http://www.sereneenergy.org/BHA-Weight-and-Weight-on-Bit.php [Accessed 1 December 2011].

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