Well_Completion_and_Stimulation——Chapter_2_Well_Completion_Design_New

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Chapter-2

Well Completion Design

Well completion design begins with well design (casing and drilling program). It is

primarily influenced by types of well completions, producing methods and a number of

zones to be completed. There are differences between each type of completion which canbe attributed to the variations in design specifications. They can be classified based on:

well completion requirements,

use of tubing and packer,

use of artificial lift techniques and

number of zones in a single or multiple completion.

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2.1 Well Completion Requirements

Structural geology, stratigraphy, formation characteristics and reservoir parameters

dictate drilling and completion practices. Accordingly most wells are completed as:

open hole completions,

uncemented liner completions and

perforated casing completions.

OPEN HOLE COMPLETION

A typical open-hole completion is shown in Fig. 2.1. The production casing is set in the

cap rock above or just on top of the pay zone, whereas the bottom of the hole is left

uncased. This type of completion has the producing interval open to the entire well bore.

It is selected for the following purposes: to increase the flow area and reducing the cost (less casing and no perforation),

to ease in deepening the well, reduction in drawdown,

to ease of interpretation of logs, lessening formation damage caused by cementing

and

to open hole completion can be converted into a liner or perforated casing

completion.

In spite of all these advantages associated with open hole completions, there are somedifficulties associated with the control of excessive gas or water production, including

well control during production and stimulation of selected pay section in the completed

interval. The open hole completion also requires frequent clean-outs if the producingsand is not competent or if the shoulder of the cap rock between the shoe and top of the

pay is not stable. Open hole wells can not be completed in layered formation consisting

of separate reservoirs with incompatible fluid properties.

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PRODUCTION CASING

Fig. 2.1: Open-hole completion, after Buzarde Jr, et al 1972

UNCEMENTED LINER COMPLETION

In early days, in order to overcome the problem of sand production, slotted pipes orscreens were used across the open-hole section which acted like a filter .These

uncemented liners are still being used as a means of sand control and this is termed as a

uncemented liner completion (see in Fig. 2.2).

In a low pressure reservoir with unconsolidated heavy oil sands, a screen linercompletion can become an effective method for controlling sand production. The

uncemented liner completion has very little potential for formation damage, minimizes

cost (less casing and no perforation) and helps control sand production.Other advantages associated with an uncemnted liner completion include:

log interpretation is less complicated,

deepening the well can easily be carried out and

hole cleanout problem can be avoided.

The screen liner completion has a number of drawbacks associated with it. Fine sand

particles can plug the slots of screen and at high rates the screen can be damaged due to

erosion. Poor support of the formation can cause intervals to collapse and plug the slots.

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P R O D U C T I O N C A S I N G

S C R E E N A N D L I N E R

A S S E M B L Y

Fig. 2.2: Uncemented liner completion, after Buzarde Jr, et al 1972

PERFORATED CASING COMPLETION

The third and most common type of completion used today is to run casing through the

production interval, cement the casing and perforate casing to provide communication for

fluid to flow into the wellbore. These perforations create a clean conduit through thedamaged zone around well bore to the formation. Selection of the perforation interval

plays a major part in reducing drawdown and increasing productivity of hydrocarbon. A

typical perforated completion is shown in Fig. 2.3.

With the use of perforated casing completion we can make production operations safer

and reduce drilling damages, which reduces the potential for dry holes. It is also easy tocontrol the well production from selected intervals and allow deepening of the well when

necessary. Unless there is a specific need to use open-hole or uncemented liner

completions, perforated casing completions are commonly used. Cased hole completionsare easy to implement but expensive due to the extra cost involved with casing and

perforations. It also restricts well bore diameter. The interpretation of logs becomes

difficult.

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PRODUCTION CASING

Fig. 2.3: Perforated cased hole completion.

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2.2 Completions based on flowing wells:

In the initial phase of production, wells usually flow by their own energy. Fluid is

allowed to flow through casing, tubing or a combination of both.

FLOW THROUGH CASING

Some wells flow at very high rates due to high reservoir drive and in such scenarios, thecasing flow completion can be implemented. Installation cost is less for this type of

completion. In a casing flow completion, the flow is up through the casing and the need

for a packer is avoided. A casing flow completion is illustrated in Fig. 2.4.

PRODUCTION CASING

Fig. 2.4: Flow through casing.

Determining the casing size is critical in completing flow through the casing completion(tubing-less) because large diameter casing can lead to liquid hold up in particular when

gas lift is used at later stages to enhance production.

FLOW THROUGH TUBING

Most wells are completed by installing a tubing and a packer where the packer acts as an

anchor for the tubing. The packer also provides a seal between the tubing and the casing-tubing annulus. This type of completion is illustrated in Fig. 2.5. Tubing is run open-

ended and is placed above the highest available completion interval which enables thru-

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tubing wire line surveys to be ran. Use of tubing provides control of flow and creates

multiple flow paths for multiple zone completion. It allows to install down hole

equipment to regulate flow and pressure and protects casing from corrosion, abrasion etc.

A packer is installed to protect casing as well as to prevent excessive tubing movement. It

provides downhole safety by containing the pressure. The use of packers and tubingallows installation of additional downhole accessories such as landing nipples and fluid

circulation devices. The effect of using a packer is different in oil wells as compared to

gas wells. In oil wells when the annulus is filled with fluid (to built pressure just aboveshut in pressure), the difference in pressure across tubing and casing-tubing annulus is

minimum and hence the likelihood of a tubing leak is minimized. While in gas wells the

difference in pressure at the well head across the tubing and casing-tubing annulus is

large and thus may lead to tubing leak.

FLOW COUPLING

SELECTIVE LANDING NIPPLE

CIRCULATING SLEEVE

PRODUCTION PACKER

TEST SUB or "NO-GO" NIPPLE

Fig. 2.5: Flow through tubing completion.

In some well completions fluid can be produced through both tubing and casing. The

capacity for fluid flow is less compared to the completions involving flow through casingonly. Completion of this type is shown in Fig. 2.6. The tubing can be installed with a

packer or without packing the casing-tubing annulus. Flow through casing and tubing

allows installation of subsurface tubing accessories for control of pressure and flow rates.

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PRODUCTION

TUBING

TEST SUB, "NO-GO" NIPPLE, ETC.

Fig. 2.6: flow through tubing and casing completion

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2.3 Completions Based on Artificial Lift

Requirements

After producing over a period of years, the reservoir pressure begins to decline. The rateof decline depends on the types of reservoir drive. When the reservoir pressure in the

formation falls below the hydrostatic head of the well bore fluid column, an additional

energy is needed to lift the fluids to the surface. This energy can be provided by injectinggas or use of down hole pumps which include: sucker rod pumping, submersible

pumping, hydraulic pumping, gas lift etc.

In a rod pumping completion, the tubing and the pump seating nipple are ran below the

fluid level .This type of completion also has an anchor (anchor catcher) which helps in

restricting movement of tubing caused by the pumping action. A typical rod pumpingcompletion is shown in Fig. 2.7.

FLUID LEVEL

TUBING ANCHOR

PUMP SEATING NIPPLE

Fig. 2.7: Rod pumping completion.

Similarly in a submersible pumping completion, the pump is immersed in the fluid. The

selection of casing size is very critical because it has to accommodate all the down hole

equipment, including the umbilical cord for electrical connection and enough coolingmechanism for the pump. The safety of the electric cable has to be taken into

consideration.

In hydraulic pumping, the power fluid (oil) is pumped through the tubing and a casingfree pump is used to lift the produced fluids through the annulus. A packer is used to

isolate the producing interval. This type of completion requires different configurations

of tubing to handle power fluids and produced hydrocarbons.

In a gas lift completion, the principle is to decrease the hydrostatic head by adding gas to

the produced fluid through the mandrels located on the tubing. A typical gas liftcompletion is shown in Fig. 2.8. This methodology can be applied in the early stage of

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decline in reservoir pressure and becomes insignificant when the reservoir pressure fall

below the critical level.

Fig.2.8: Gas lift completion.

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2.4 Multiple Completions

It is common to have several reservoirs lying one above the other. These reservoirs can

be completed by a single well. Then the decision is to be made whether or not thesereservoirs are to be produced individually or comingled led by a single string. Some

completions of this type include single string multiple completions, cross-over dual

completion with single string and parallel dual and triple completions.In single string alternate completion both the zones are perforated in the initial

completion but produced one after the other. The producing intervals are isolated

between packers and production is carried out from alternate zone. This is achieved by

producing from the lower zone first. Once the lower zone is depleted the upper zone isbrought into production. Additional devices (blast joints) are needed for protecting tubing

against wear caused due to fluid induced erosion. A typical completion of this type is

shown in Fig. 2.9.

Fig. 2.9: Single string alternate zone completion.

In a cross-over dual completion it is easier to produce either of the zones (primary or

alternate zone). This can be achieved by utilizing a circulating sleeve. In spite of theadvantage of producing from the desired zone through the annulus, this completion will

lead to the exposure of fluids into the casing which can cause casing wear. In order to

perform any workover operation in the upper zone it will be necessary to kill the zone

beneath it.

In parallel dual completion design, the two tubings can produce simultaneously from

different zones. This design can be adapted to techniques for sand control. Artificial lift

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can be employed to either of the zones and proration (distribution of crude oil or natural

gas to some fractional part of the total capacity of each producer) is more effective.

Disadvantages include:

the design requires higher initial investment and

the workover operation is difficult as it requires removal of the current setting of

production equipment.A typical completion of this type is shown in Fig. 2.10. This type of completion can beextended to parallel dual with two alternate completions.

Triple completions are similar to parallel dual completions but can have more than twotubing strings. This type of completion reduces the production from individual reservoirs

and problems arise in installation of downhole accessories for flow and pressure

regulation as well as communication.

Fig. 2.10: parallel dual completion

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2.5Monobore Completions

Monobore completions are cemented casings with the exception being that smaller

diameter tubings of 3 to 6 size are used to save material cost and reduce drilling andcompletion time. This type of completion has been very attractive for smaller and

marginal field development. When implementing this design, it is hard to achieve a good

cementing job. It can lead to corrosion of casing due to fluids being exposed to thecasing. A typical monobore completion is presented in Fig. 2.11.

L N

Fig. 2.11: A typical monobore completion.

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2.6 Reservoir Considerations in Well Completion

Reservoirs are characterized based on the drive mechanism They are classified as:

solution gas drive reservoir

water drive reservoir and

gas-cap expansion drive reservoirs.

Figure 2.12 illustrates various producing mechanisms.

GAS

OIL

OIL

H2O

OIL

GAS

GAS CAP

OIL

GAS CAP

Fig. 2.12: Reservoir drive mechanisms.

Solution Gas Drive Reservoir:The oil production in solution gas drive reservoir can purely be attributed to the

volumetric expansion of solution gas and is not assisted by either water encroachment orgas cap expansion. In this type of reservoir the pressure decline is very rapid and oil

production is reduced due to excessive drawdown (large difference between well bore

pressure and reservoir pressure). A regular spacing pattern of wells has to be drilled andcompleted for this type of reservoir. It is certain that some kind of secondary recovery is

needed in later stages of production and this has to be kept in mind when completing the

well initially.

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S E L E C T I V E P E R F O R A T I O N

T E C H N I Q U E

" B L A N K E T " P E R F O R A T I O N

T E C H N I Q U E

Fig. 2.13: Perforation interval for a typical solution gas drive reservoir.

Water Drive Reservoir:

In water drive reservoirs the produced oil is replaced by water and hence the decline in

the pressure is not as rapid as solution gas drive reservoirs. The same pattern of wells canbe employed as in solution gas drive reservoirs. Completion intervals should be selected

high on the structure, so that it enables longer period of production as water encroaches.

An irregular spacing pattern has to be employed if the reservoir is in thin sand with highangle of dip because of the structural characteristics. Perforation interval for water drive

reservoirs is presented in Fig. 2.14.

WATER

OIL

Fig. 2.14: Water drive reservoir.

Gas Cap Expansion Drive Reservoir:

In gas cap drive reservoirs, the produced oil is replaced by the expansion of the gas capabove the oil zone and is illustrated in Fig. 2.15.

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Fig. 2.15: Gas drive reservoir.

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2.7 Effect of Reservoir Heterogeneity

Most petroleum reservoirs are heterogeneous in nature. Permeability and porosity in a

heterogeneous reservoir vary along both vertical and horizontal directions. A typicalpermeability variation for both water and gas driven reservoirs are shown in Fig. 2.16 and

Fig. 2.17. Elkins et al have shown that due to variation in vertical permeability water and

or gas breakthrough can take place earlier than expected if perforation interval is not

selected appropriately. For example, selection of perforation interval in high permeabilitystreak as shown in Figs. 2.16 and 2.17 may lead to early water or gas breakthrough.

W A T E R

O I L

M E D I U M P E R M E A B I L I T Y

H I G H P E R M E A B I L I T Y


WATER

Fig. 2.16: Water break through along high permeability streak.

O I L

GAS

M E D I U M

P E R M E A B I L I T Y


H I G H

P E R M E A B I L I T Y

G A S

Fig. 2.17: Gas break through along high permeability streak.

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2.8 Effect of Partial Penetration

A partially penetrated well is the one in which only a fraction of the total productive

interval is perforated. This is often carried out to avoid early water or gas break throughby placing the perforation interval away from water aquifer or gas cap as discussed in

Section 2.6. The study by Buzarde Jr., 1972 has shown that the partial penetration often

leads to water or gas coning (See Fig. 2.18, Fig. 2.19).

W A T E R

W A T E R C O N E

O I L

Fig. 2.18: Water coning due to partial penetration.

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O I L

G A S

G A S C O N E

Fig. 2.19: Gas coning due to partial penetration.

Muskat, 1949 has also shown that the productive capacity of a reservoir is highlydependant on the percentage flow area open to the well. In Fig. 2.20 Muskats data is

graphically presented. From this figure it is clear that for a 130 ft productive interval the

fractional penetration of 0.8 and 0.4 can result in productivity ratios of 0.87 and 0.52respectively. This means that for a productive interval of 130 ft the perforation interval of

52 ft (40% of the total productive) would result in a production loss of 48%.

Fig. 2.20: Reduced production rate due to partial penetration, from Muskat, 1949.

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Another example of partial penetration effect is skin damage. Skin damage is defined as

the reduction in near well bore permeability due to drilling and completion practices.Numerous studies have shown that near well bore damage affects the capacity of

production interval severely. The productive capacity of many prospective exploration

wells went unnoticed and became dry holes due to skin damage. The effect of skindamage on productivity can be explained using Fig. 2.21.

Fig. 2.21: Effect of partial penetration and skin damage on available BHP.

EFFECT OF SKIN ON PRODUCTIVITY INDEX

In calculations of the productivity of oil wells, it is commonly assumed that production is

directly proportional to drawdown. The constant of proportionality is termed

productivity index, and commonly denoted as PIorJ.

wfR pp

qJ

= (2.1)

For pseudo steady state flow of slightly compressible fluids we can say that:

+

=

Sr

rB

pphkQ

w

eoo

wfRo

o

75.0ln2.141

)(

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Substituting the above equation into Eq. (2.1) we can say the PI for well producing 100%

oil is

+

=

Sr

r

B

hkPI

w

e

oo

o

75.0ln2.141 STB/d/psi

or

+

=

Sr

rB

hkPI

w

eoo

o

75.0ln1866m3/s/kPa (2.2)

Where,

ko= effective permeability to oil, mDh= thickness of pay, m (ft)

o= oil viscosity, mPa.s (cp)

Bo= oil formation volume factor, m3/ST m3 (rb/STB)

re= effective radius of reservoir, m (ft)rw= wellbore radius, m (ft)

S= skin factor

Since PI relates to the total fluid produced, the magnitude ofPI can change as the watercut changes. This can be important for sizing artificial lift and treating facilities to handle

expected fluid production after water breakthrough on a flood operation.

Example 2.1:Effect of Skin on PI:

Example of a PIcalculation showing effects of

a. wellbore damage (S= + 2)

b. fracture stimulation (S= - 2)

c. a good normal completion (S= 0)

re= 600 fto= 1.5 cp (mPa.s)

k= permeability of rock, 400 md

h= 40 ftrw= 0.25 ft

S= variable

Rp = 3000 psi

Bo= 1.4 vol/vol

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Solution:

Using Eq. (2.2)

[ ]6000.25

400 40

141.2 1.5 1.4 ln 0.75

53.59

7.033

J

S

S

=

+

=

+

(a) S = + 2

J = 5.97 stb/d/psi

(b) S = - 2

J = 10.7 stb/d/psi

(c) S = 0

J = 7.67 stb/d/psi

(c) - (a)Effect of damage

(c)

22% loss in PI

=

=

(c) - (a)Reward for stimulation

(a)

28% increase in PI

=

=

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Review questions

1. What are advantages and disadvantages of open-hole or barefoot completions?

2. Draw a diagram showing all essential components of a gas-lift well and explain how

it works.

3. A gas well with tubingless completion (i.e. casing flow) has been producing for anumber of years, but now has liquid-lifting problems. What would you do to resurrect

the well?

4. To reduce completion costs, reduced diameter completions are sometimes used. Butwhat are major limitations of this type of completion?

5. As a completion engineer, what would you consider as critical issues that need to beevaluated when designing a completion?

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REFERENCES

1. Allen, TO and Roberts, AP, Well Completion Design- Production Operations-1, 3 rd

edition, 1989, pp 143-149.

2. Buzarde Jr, LE,Kastor, RL ,Bell, WT and DePriester,CL,1972,Well Completionpractices-Production Operations Course -1,1972, pp 1-44.

3. Brown, KE, Overview of Artificial Lift Systems, SPE 9979, SPE-AIME, 1982.

4. Dake, LP, Fundamentals of Reservoir Engineering, NY, Elsevier, 1978.

5. Elkins, LF, Skov, AM and Liming, HF, A Practical Approach to Finding andCorrecting Perforation Inadequacies, Preprint of paper 2998 presented at 45 th Annual

Fall Meeting of SPE, Houston, Texas,1970.

6. Fetkovich, MJ, The Isochronal Testing of Oil Wells, SPE 4529, SPE-AIME, 1973.

7. Fetkovich, M.J, Multipoint Testing of Gas Wells, SPE Mid-continent sectionContinuing Education Course of Well Test Analysis, March 17 1975.

8. Golan, M and Whitson, C, Well Performance, International Human ResourcesDevelopment Corporation, 1986.

9. Muskat, M and Evinger, HH, Calculations of Theoretical Productivity Factor, Trans,

AIME, 1942, pp126-139.

10. Muskat, M, Physical Principles of Oil Production, McGraw-Hill Book Co, Inc, NY

1949, pp 210-214.

11. Standing, MB, Inflow Performance Relationships for Damaged Wells Producing by

Solution-Gas Drive, JPT, Nov 1970, pp1399-1400.

12. Standing, MB, Concerning the Calculation of Inflow Performance of Wells Producing

From Solution-Gas Drive Reservoirs, JPT, pp1141-1142.

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