53939135 ENI Completion Design Manual

•

The PVTs are reliable, Y(H2S) >0.2%, the partial pressure is calculated as: pH2S = Y(H2S) x FBHP 1 where: Y(H2S) =

•

Molar olar fracti fraction on in gas separ separate ated d at at FBH FBHP P and and at rese reserv rvoi oirr temperature (from PVT)

The PVTs are not reliable, the material balance method can be used as in the case of undersaturated oil; these are the worst conditions. The error made can be high when P b > FBHP.

Calculation Of Partial Pressure At Wellhead

The calculation method is that used for case A (FTHP
1

2

If the percentage (ppm) of H 2S in the gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead. 2 If the percentage (ppm) of H S in the separated gas under static conditions is not known, the 2 corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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-

Corrosion Caused By CO2 And Cl

In the presence of water, CO 2 gives rise to a corrosion form which is different to those caused by the presence of H2S. It also occurs only if the partial pressure of CO 2 exceeds a particular threshold. As in the case of SSC, the possibility that corrosions exist in water cut values combined with the type of well and deviation profile is evaluated. If the conditions described in section 6.3.1 exist, then the pCO 2 is then calculated. Gas Or Condensate Gas Wells

The partial pressure is calculated: pCO2 = SBHP x Y(CO2)/100 where: SBHP = Y(CO2) = pCO2 =

Static bo bottom-hole pr pressure [a [atm] Mole fraction of CO2 Partial pressure of CO CO2 [atm]

Corrosion occurs if pCO 2 >0.2 atm. Oil Bearing Wells

The problem exists where there is wetting water; i.e.:

• •

Water cut >15% for vertical wells. Water cut >1% for horizontal or highly deviated wells (> 80 degrees).

Undersaturated Oil Wells

The partial pressure of CO 2 is calculated: pCO2 = Pb x Y(CO2)/100 where: Pb = Y(CO2) = pCO2

=

Bubb Bubble le poin pointt pre press ssur ure e at at res reser ervo voir ir temp temper erat atur ure e Mole f raction of CO2 in separated gas at bubble point pressure (from the PVTs) Partial pressure of CO CO2 [atm]

Corrosion occurs if pCO 2 >0.2 atm. The pCO2 values calculated in this way are used to evaluate the corrosion at bottom hole and wellhead; i.e. pCO 2 at wellhead is assumed as corresponding to reservoir conditions.

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Oversaturated Oil

The oil is considered oversaturated when the gas separates in the fluid because the pressure of the system is lower than bubble point pressure. Two situations may arise: Case A FTHP Pb Case B FTHP
Calculation of pCO 2 in reservoir conditions: FBHP >Pb pCO2 is calculated in the same way as undersaturated oil wells earlier in this section. pCO2 = Pb x Y(CO2)/100 where: Pb = Y(CO2) = pCO2 =

Bubb Bubble le poin pointt pre press ssur ure e at at res reser ervo voir ir temp temper erat atur ure e Mole ole frac fracti tion on in separ separate ated d gas gas at bubbl bubble e poi point nt pres pressu sure re (from (from the PVTs) PVTs) Partial pressure of CO CO2 [atm]

Corrosion occurs if pCO 2 >0.2 atm. Calculation Of pCO2 At Wellhead:

pCO2 = STHP x Y(CO2)/100 where: Y(CO Y(CO2) 2) = STH STHP =

Mole ole frac fracti tion on in sepa separa rate ted d gas gas at STHP STHP3 Stat Static ic tubi tubing ng head head pres press sure ure [atm [atm]]

Corrosion occurs if pCO 2 >0.2 atm.

3

If the percentage (ppm) of CO 2 in the gas under static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead

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Calculation Of Partial Pressure In Case B:

Calculation of pCO 2 at reservoir conditions: pCO2 = FBHP x Y(CO2)/100 where: Y(CO2)

=

Mole ole frac fracti tion on in sepa separa rate ted d gas gas at pres pressu sure re FBHP FBHP (fro (from m the the PVTs PVTs))

Calculation Of pCO2 At Wellhead:

The calculation method is the same as the one used in the wellhead conditions in case A: pCO2 = STHP x Y(CO2)/100 where: Y(CO2) =

Mole ole frac fracti tion on in sepa separrated ated gas gas at STH STHP4

There is corrosion if pCO 2 >0.2 atm. 6.3.3.

Corrosion Caused By H2S, CO2 And Cl-

It is possible to encounter H2S and CO2 besides Cl . In this case the problem is much more complex and the choice of suitable material is more delicate. The phenomenon is diagnosed by calculating the partial pressures of H 2S and CO2 and comparing them with the respective thresholds.

4

If the percentage (ppm) of CO 2 in the gas under flowing/static conditions is not known, the corresponding value in reservoir conditions is assumed as being partial pressure at the wellhead.

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CORROSION CORROSIO N CONTROL MEASURES

Corrosion control measures may involve the use of one or more of the following:

• • • • • • • • • • • • • • • • •

Cathodic protection Chemical inhibition Chemical control Oxygen scavengers Chemical sulphide scavengers pH adjustment Deposit control Coatings Non metallic materials or metallurgical met allurgical Control Stress reduction Elimination of sharp bends Elimination of shock loads and vibration Improved handling procedures Corrosion allowances in design Improved welding procedures Organisation of repair operations.

Refer to table 6.a below. Measure

Control of the environment

Surface treatment Improvement of the corrosion resistivity of the steel

Means

• • • • • • • • • • •

pH Temperature Pressure Chloride concentration CO2 concentration 2 H S concentration 2 H O concentration Flow rate Inhibitors Plastic coating Plating

Addition of structure

the

alloying

Table 6.A - Counter Measures to Prevent Corrosion

elements

micro

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CORROSION INH INHIBITORS IBITORS

An inhibitor is a substance which retards or slows down a chemical reaction. Thus, a corrosion inhibitor is a substance which, when added to an environment, decreases the rate of attack by the environmental on a metal. Corrosion inhibitors are commonly added in small amounts to acids, cooling waters, steam or other environments, either continuously or intermittently to prevent serious corrosion. There are many techniques used to apply corrosion inhibitors in oil and gas wells:

• • • • • • 6.6.

Batch treatment (tubing displacement, standard batch, extended batch) Continuous treatment Squeeze treatment Atomised inhibitor squeeze - weighted liquids Capsules Sticks.

CORROSION RESISTANCE RESISTANCE OF STAINLESS STAINLESS STEELS

Stainless steel is usually used in applications for production tubing, however it is occasionally used for production casing or tubing below the packer depth. The main reason for the development of stainless steel is its resistance to corrosion. To be classed as a stainless steel, an iron alloy usually must contain at least 12% chromium in volume. The corrosion resistance of stainless steels is due to the ability of the chromium to passivate the surface of the alloy. Stainless steels may be divided into four distinct classes on the basis of their chemical content, metallurgical structure and mechanical properties these are: 6.6.1.

Martensitic Martensitic Stainless Steels

The martensitic stainless steels contain chromium as their principal alloying element. The most common types contain around 12% chromium, although some chromium content may be as high as 18%. The carbon content ranges from 0.08% to 1.10% and other elements such as nickel, columbium, molybdenum, selenium, silicon, and sulphur are added in small amounts for other properties in some grades. The most important characteristic that distinguishes these steels from other grades is their response to heat treatment. The martensitic stainless steels are hardened by the same heat treatment procedures used to harden carbon and alloy steels. The martensitic stainless steels are included in the ‘400’ series of stainless steels. The most commonly used of the martensitic stainless steels is AISI Type 410. The only grade of oilfield tubular used in this category is 13Cr. As their name indicates, the microstructure of these steels is martensitic. Stainless steels are strongly magnetic whatever the heat treatment condition.

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Ferritic Stainless Steels

The second class of stainless steels, is the ferritic stainless steels, which are similar to the martensitic stainless steels in that they have chromium as the principal alloying element. The chromium contents of ferritic stainless steels is normally higher than that of the martensitic, stainless steel, and the carbon content is generally lower. The chromium content ranges between 13% to 27% but are not able to be hardened by heat treatment. They are used principally for their temperature properties. Ferritic stainless steels are also part of the ‘400’ series, the principal types being 405, 430, and 436. The microstructure of the ferritic stainless steels consists of ferrite, which are also strongly magnetic. Ferrite is simply body cantered cubic iron or an alloy based on this structure. 6.6.3.

Austenitic Austenitic Stainless Steels

The austenitic stainless steels have two principal alloying elements, chromium and nickel. Their micro-structure consists essentially of austenite which is face cantered cubic iron or an iron alloy based on this structure. They contain a minimum of 18% chromium and 8% nickel, with other elements added for particular reasons, and may range up to as high as 25% chromium and 20% nickel. Austenitic stainless steels generally have the highest corrosion resistance of any of the stainless steels, but their strength is lower than martensitic and ferritic stainless steels. They are not able to be hardened by heat treatment although they are hardenable to some extent by cold working and are generally non-magnetic. Austenitic stainless steels are grouped in the ‘300’ series, the most common being 304. Others commonly used are 303 free machining, 316 high Cr and Ni which may include Mo, and 347 stabilised for welding and corrosion resistance. These steels are widely used in the oilfield for fittings and control lines, but due to its low strength is not used for well tubulars. 6.6.4.

Precipitation Hardening Stainless Steels

The most recent development in stainless steel is a general class known as ‘precipitation hardened stainless steels’, which contain various amounts of chromium and nickel. They combine the high strength of the martensitic stainless steels with the good corrosion resistance properties of the austenitic stainless steels. Most were developed as proprietary alloys, and there is a wide variety of compositions available. The distinguishing characteristic of the precipitation hardened stainless steel is that through specific heat treatments at relatively low temperatures, the steels can be hardened to varying strength levels. Most can be formed and machined before the final heat treatment and the finished product being hardened. Precipitation in alloys is analogous to precipitation as rain or snow. These are most commonly used for component parts in downhole and surface tools and not as oilfield tubulars. Refer to figure 6.b for the various compositions of stainless steels.

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Figure 6.B- Stainless Steel Compositions

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Duplex Stainless Steel

In general, ferritic-austenitic (duplex) stainless steel consists of between 40-70% ferrite and has a typical composition of 22% Cr-5.5% Ni-3% Mo-0.14% N. The resulting steel has properties that are normally found in both phases: the ferrite promotes increased yield strength and resistance to chloride and hydrogen sulphide corrosion cracking; while the austenite phase improves workability and weldability. This material is used extensively for tubulars used in severe CO 2 and H2S conditions. As a general note, there is a large gap between the 13Cr and Duplex Stainless Steels used as tubulars for their good anti-corrosion properties. This gap is attempted to be filled with ‘Super 13Cr’ tubing being developed. 6.7.

COMPANY DESIGN PROCEDURE

6.7.1.

CO2 Corrosion

In producing wells, the presence of CO 2 may lead to corrosion on those parts coming in contact with CO2 which normally means the production tubing and part of the production casing below the packer. Corrosion may be limited by:

• • 6.7.2.

The selection of high alloy chromium steels, resistant to corrosion. Inhibitor injection, if using carbon steel casing. Generally, wells producing CO 2 partial pressure higher than 20psi requires inhibition to limit corrosion.

H2S Corrosion

In wells, where there is H2S, consideration should be given to limit casing and wellhead yield strength according to API 5CT and ‘NACE’ standard MR-01-75. Casing and tubing material will be selected according to the amount of H 2S and other corrosive media present. Refer to figure 6.c and figure 6.d for partial pressure limits.

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Figure 6.C - Sour Gas Systems

Figure 6.D - Sour Multiphase Systems Systems

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MATERIAL MA TERIAL SELECTION

The choice of material is based on the application of engineering diagrams supplied by manufacturers of tubing and, hence the use of the modified SMI has been adopted, refer to figure 6.e and figure 6.f. The choice of materials proposed is conservatively as recent develop materials such as 13%Cr and Super Duplex class have not been considered because experiments on these materials are not completed. In the partial pressures of H2S and CO2 are below the critical thresholds established in the previous section, all materials in class C-steel/L-A-steel can be used, otherwise the following combinations of conditions may exist:

• • • •

Solely H2S in oil wells Solely H2S in gas or gas condensate wells Solely CO2 and Cl Both H2S and CO2.

The tables regarding the choice of materials are shown below. These give the rules used by Eni-Agip sectioned on the basis of the conditions as listed above and the use in the well. Materials are sub-divided into three categories, OCTG, DHE materials and wellhead materials.

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OCTG Specifications

Refer to table 6.b below. OCTG Materials For Corrosion By H 2S Only In Oil Wells Conditions o

0.0035< pH2S m ax < 0.1 0.0035< pH2S m ax < 0.1 0.0035< pH2S m ax < 0.1 pH2S m ax < 0.1

FBHT >80 C o 60 C< FBHT >80 C o FBHT >80 C o

Material

Alternately

J55, K55, N80, C95, P110 J55, K55, N80 L80 L80 Mod, C90-1, T95-1

L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1

OCTG Materials For Corrosion By H 2S Only In Gas Wells Conditions o

0.0035< pH2S m ax < 0.1 0.0035< pH2S m ax < 0.1

FBHT >80 C o FBHT <80 C

Material

Alternately

J55, K55, N80-2, C95 L80

L80-Mod, C90-1, T95-1 L80-Mod, C90-1, T95-1

OCTG Materials For Corrosion By CO 2 And Cl* Conditions 0.2< pCO2S max <100 0.2< pCO2S max <100 0.2< pCO2S max <100

o

FBHT <150 C o 150 C< FBHT <200 C o o 200 C< FBHT <250 C

Cl* <50,000

o

Material

Alternately

13% Cr 22% Cr 25% Cr-SA

25% Cr

OCTG Materials For Corrosion By CO 2 , H2S And Cl* Conditions 0.2< pCO2S max <100e 0.0035< pH2S max < 0.005 0.2< pCO2S max <100e pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.0035< pH2S max <0.005 0.2< pCO2S max <100e 0.005< pH2S max <0.1 pCO2S max <100e 0.005< pH2S max <0.1 0.2< pCO2S max <100e 0.005< pH2S max <0.1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e 0.1< pH2S max <1 0.2< pCO2S max <100e pH2S max >1

o

o

FBHT <150 C

FBHT <200 C

Material

Alternately

Cl* <50,000

13% Cr-80KSI Max

22% Cr 25% Cr

Cl* >50,000

o

o

Cl* <50,000

o

o

Cl* <50,000

22% Cr CW 25% Cr CW 22% Cr 25% Cr 25% Cr

o

o

Cl* >50,000

25% Cr CW

o

Cl* <20,000

25% Cr

o

Cl* <50,000

25% Cr CW

Cl* <50,000

28% Cr

o

Cl* <50,000

22% Cr SA

o

Cl* <50,000

25% Cr SA

o

Cl* >50,000

28% Cr

22% Cr, 25% Cr Incoloy 825 28% Cr Incoloy 825 Incoloy 825

28% Cr

Incoloy 825

150 C< FBHT <200 C 200 C< FBHT <250 C 200 C< FBHT <250 C FBHT <250 C FBHT <250 C o

o

200 C< FBHT <250 C FBHT <200 C FBHT <250 C FBHT <200 C

Table 6.B - OCTG O CTG Materials for Sour Service

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DHE Specifications

Refer to table 6.c below. Materials For DHE Corrosion By H2S Only In Oil Wells Conditions

Material o

pH2S m ax < 0.1 pH2S m ax < 0.1 pH2S m ax < 0.1 pH2S m ax > 0.1

FBHT >80 C o FBHT >80 C o FBHT <65 C o FBHT <65 C

Alternately

AISI-41XX-110KSI-MAX AISI-41XX-80KSI-MAX AISI-41XX-HRC-22-MAX AISI-41XX-HRC-22-MAX

Materials For DHE Corrosion By H2S Only In Gas Wells Conditions

Material o

pH2S m ax < 0.1 pH2S m ax < 0.1

FBHT >80 C

Alternately

AISI-41XX-80KSI-MAX AISI-41XX-HRC-22-MAX AISI-41XX-HRC-22-MAX

o

FBHT <80 C

Materials For DHE Corrosion By CO2 And Cl* Conditions pCO2S m ax <100 pCO2S m ax <100 pCO2S m ax <100

o

FBHT <100 C o 100 C< FBHT <150 C o o 150 C< FBHT <250 C o

Material

Alternately

28% Cr

Inconel 718 Incoloy 825

Cl* <50,000 Cl* <50,000

Materials For DHE Corrosion By CO2 , H2S And Cl* Conditions pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max <0.005

Material o

FBHT <100 C

Cl* <50,000

9% Cr-1Moly

o

o

Cl* <50,000

13%-Cr-80KSIMAX

o

o

Cl* <50,000

o

o

Cl* <50,000

o

o

Cl* >50,000

22% Cr 25% Cr 25% Cr Inconel 718 Incoloy 825 22% Cr CW 25% Cr CW

o

o

Cl* >50,000

25% Cr CW

o

o

Cl* <50,000

25% Cr

o

o

Cl* >50,000

28% Cr

o

Cl* <50,000

22% Cr SA 25% Cr SA

o

Cl* <50,000

o

Cl* >50,000

25% Cr SA 28% Cr 28% Cr

100 C< FBHT <150 C 150 C< FBHT <250 C 200 C< FBHT <250 C

pCO2S max <100e pH2S max <0.005 pCO2S max <100e pH2S max < 0.005 pCO2S max <100e pH2S max <0.1 pCO2S max <100e pH2S max <0.1 pCO2S max <100e pH2S max <1

100 C< FBHT <150 C

pCO2S max <100e pH2S max <1 pCO2S max <100e pH2S max <1

FBHT <250 C

150 C< FBHT <250 C 200 C< FBHT <250 C 200 C< FBHT <250 C FBHT <200 C

FBHT <250 C

Table 6.C- DHE Material for Sour Service

Alter

Or

22% Cr 25% Cr Inconel 718 Incoloy 825

Inconel 718 Incoloy 825

Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 22% Cr, Inconel 718 Incoloy 825 Inconel 718 Incoloy 825 Inconel 718 Incoloy 825

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Wellhead Specifications

Refer to below. Wellhead Materials For Corrosion Caused By H 2S Conditions

Tubing Hanger

Tbg Head Adapter

Tubing Spool

Cross

Top Adapter

Casing Spool

Stud

Nut

pH2S-MAX > 0.035

AISI-4140 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

AISI-4135 HRC-22MAX

ASTMA193-B7M

ASTMA194-2M

pH2S-MAX < 0.035

AISI-4140

AISI-4135

AISI-4135

AISI-4135

AISI-4135

AISI-4135

ASTMA193-B7M

ASTMA194-2H

Autom atic-M aster-Valve

M anual M aster-Valve

Conditio ition ns

Body Bonnet Flanges

Gate & Seats

Steam

Body Bonnet Flanges

Gate & Seats

Steam

pH2S-MAX> 0.035

AISI-4135HRC-22-MAX

AISI-4140HRC-22-MAX

AISI-4140HRC-22-MAX

AISI-4135HRC-22-MAX

AISI-4140HRC-22-MAX

AISI-4140 HRC-22-MAX

pH2S-MAX < 0.035

AISI-4135

AISI-4140

AISI-4140

AISI-4135

AISI-4140

AISI-4140

Wellhead Materials For Corrosion Caused By CO2 and ClConditions

Tubing Hanger

Tbg Head Adapter

Tubing Spool

Cross

Top Adapter

Casing Spool

Stud

Nut

0.2
13%-Cr80ksi-Max F6NM

13%-Cr80ksi-Max F6NM

AISI-4135

13%-Cr80ksi-Max

13%-Cr80ksi-Max F6NM

Carbon-Steel AISI-41XX

ASTMA193-B7

ASTMA194-2H

Monel-K500 Inconel-718

AISI-4135-IC

AISI AISI-4 -41 135

AISI-4135-IC

AISI-4135

ASTMA193-B7

ASTMA194-2H

-

FTHT < 150 Cl < 50000 pCO2-Max < 100 150
F6NM

Inconel-625

-

Cl < 50000

AISI AISI-4 -41 135IC Inconel 625 MonelK500

Inconel -625 Monel-K500

Automatic-Master-Valve

Manual Ma Master-Valve

Conditions

Body Bonnet Flanges

Gate & Seats

Steam

Body Bonnet Flanges

Gate & Seats

Steam

0.2 < pCO2-Max < 100e

13%-Cr-80ksiMax

13%-Cr-80ksiMax

Monel-K500

13%-Cr80ksi-Max

13%-Cr80ksi-Max

Monel-K500

FTHT < 150e Cl < 50000

F6NM

17-4-PH

F6NM

pCO2-Max <100e

AISI-4135-IC

Inconel -718

AISI-4135-IC

150
Inconel-625

-

Cl < 50000

Inconel -718

Inconel-625

17-4-PH Inconel-718

Inconel-718

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Tubing Hanger

Tbg Head Adapter

Tubing Spool

Cross

pCO2 -Max < 100

F6NM

13%-Cr 80ksi-Max

AISI-4135 HRC-22Max

13%-Cr80ksi-Max

AISI-4135HRC-22Max

F6NM

AISI-4135HRC-22MAX

F6NM

pH2S-Max < 0.005

148

F6NM

F6NM

Top Adapter

-

Casing Spool

Stud

13%-Cr AISI-4135 ASTM80ksi-Max HRC-22-Max A193-B7M F6NM

Nut ASTMA194-2M

FTHT < 150 Cl < 50000

pCO2-Max < 100

F6NM

pH2S-Max < 0.2

MonelK500

FTHT < 150

F6NM

F6NM

AISI-4135 ASTMHRC-22-Max A193-B7M ASTMA194-2M

Cl < 50000

pCO2-Max < 100

F6NM

pH2S-Max < 0.2

MonelK500

FTHT < 150

F6NM

F6NM

AISI-4135HRC-22MAX

ASTMA193-B7M

AISI-4135 HRC-22MAX

MonelK500

MonelK500

Inconel718

Inconel718

Cl < 50000

pCO2-Max < 100 pH2S-Max <0.8

Inconel718

Inconel625

FTHT< 150 Cl < 50000

pCO2-Max < 100 pH2S-Max <0.8 -

Cl > Water 50000 pCO2-Max <100 pH2S-Max e > 0.8

AISI-4135IC

Inconel718

AISI-4135IC Inconel625

AISI-4135 HRC-22MAX

AISI-4135 HRC-22Max

ASTMA194-2M

AISI-4135- AISI-4135IC IC Inconel625

Inconel625

MonelK500

MonelK500

AISI-4135- AISI-4135- AISI-4135 IC IC HRC-22-Max Inconel625

Inconel625

Inconel718

Inconel718

ASTMA194-2M

ASTMA194-2M

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pCO2 -Max < 100 13%-Cr-80KSIMax pH S- Max < 2

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Manual Ma Master-Valve

Gate & Seats

Steam

Body Bonnet Flanges

Gate & Seats

Steam

13%-Cr-80 KSIMax

17-4 17-4-P -PH H F6NM F6NM

13%-C 13%-Cr-8 r-80K 0KSI SI-Max

13%-Cr80KSI- Max

17-4-PH

13%-Cr80KSI- Max -

Monel-K500

F6NM

F6NM

F6NM

FTHT < 150 Cl < 50000

pCO2- Max < 100

F6NM

pH2S- Max < 0.2

13%-Cr-80 KSIMax

FTHT < 150

Stellite-6

Monel-K500

F6NM

Stellite--6

Cl < 50000

pCO2- Max < 100

AISI-4135-I.C.

F6NM

pH2S- Max < 0.8

Inconel-625

Inconel-718

Monel-K l-K500

AISIISI-4 4135-I.C I.C.

F6NM

Inconel-625

Inconel-718

AISI-4135-I.C.

Inco Incon nel-7 l-718

Monel-K500

FTHT< 150 -

Cl <50000 pCO2- Max < 100 AISI-4135- I.C. pH2S- Max < 0.8

Inconel-625

Inconel-718

Inconel-718

Inconel-625

-

Cl Water 50000 pCO2- Max < 100 pH2S- Max e > 0.8

Table 6.D- Wellhead Material for Sour Service

Inc Inconel-7 l-718

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100

10

1

FBHT <= 150 C and Cl- <= 50000 ppm 13% Cr

FBHT<= 250 C and Cl- <= 20000 ppm 25% Cr-CW

150 > FBHT <= 200 C Cl- <= 50000 ppm 22% Cr

FBHT<=250 C and Cl- <= 50000 ppm 25% Cr-CW

200
10-1

(*)

200 50000 ppm 28 % Cr or INCOLOY- 825

0

FBHT <= 200 C Cl-<=50000 ppm 22 % Cr-SA or 25 % Cr-SA 28 % Cr INCOLOY- 825

(*)

FBHT < 200 C 28 % Cr or INCOLOY-825

FBHT <= 250 C Cl- <= 50000 ppm 25 % Cr-SA or 28 % Cr INCOLOY- 825 FBHT<= 250 C Cl- > 50000 ppm 28 % Cr INCOLOY- 825

C- STEEL J 55 N 80 P 110

10-3

200 < FBHT <= 250 Cl- > 50000 ppm 25 % Cr-CW

FBHT >80 C J55 K55 N80-1 C95 P110-1 (only oil) or L80 mod C90 T1

LOW ALLOY STEEL L 80 mod C 90 T1 C 95 T1

10-4

10-3

10-2

FBHT <= 200 C Cl- > 50000 ppm 22 % Cr- CW 25 % Cr -CW

200 < FBHT <= 250 C Cl- < 50000 ppm 25 % Cr-CW

65 < FBHT<= 80C J 55 K 55 N80-1 or L 80 mod C90 T1 T 95 T1

10-4

FBHT<= 150 C Cl- <= 50000 ppm 13 % Cr 80 Ksi max or 22 % Cr 25 % Cr

150 < FBHT <= 200 C Cl- < 50000 ppm 22 % Cr 25 % Cr Cr

FBHT < = 65 C L 80 or L 80 mod;C 90 T1 T 95 T1

10-2

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pCO2 (atm)

150

10-1

1

10 100 pH2S (atm)

Figure 6.E - OCTG OCT G Material Selection Diagram

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100

10

1

FBHT <= 100 C Cl- <= 50000 ppm 9 Cr 1 Mo 100 < FBHT <= 150 C Cl- <= 50000 ppm 13 % Cr 80 ksi max 150 > FBHT<= 250 C 25% Cr-CW or 25% Cr INCONEL 718 INCOLOY 825

10-1

200 < FBHT<= 250 C Cl- <= 50000 ppm 25 % Cr or INCONEL 718 INCOLOY 825

(*) 200 < FBHT<=250 C Cl- > 50000 ppm 28 % Cr or INCONEL 718 INCOLOY 825

0

FBHT <= 200 C Cl-<=50000 ppm 22 % Cr-SA 25 % Cr-SA 28 % Cr INCOLOY 825 INCONEL 718

(*)

200 < FBHT <= 250 C Cl- <= 50000 ppm 25 % Cr-SA 28 % Cr INCOLOY 825 INCONEL 718

FBHT < 200 C 28 % Cr or INCOLOY 825 INCONEL 718

C-STEEL or AISI 41XX

100 < FBHT <= 200 C Cl- > 50000 ppm 22 % Cr-CW 25 % Cr-CW INCONEL 718 INCOLOY 825

65 < FBHT <=80 C C-STEEL 80 Ksi max AISI 41XX

200 > FBHT <= 250 C Cl- > 50000 ppm 25 % Cr-CW INCONEL 718 INCOLOY 825

AISI 41XX 22 HRC max

FBHT > 80 C C-STEEL 110 Ksi max AISI 41XX

10-3

10-4

10-4

10-3

10-2

150 < FBHT <= 200 C Cl- <= 50000 ppm 22 % Cr 25 % Cr INCONEL 718 INCOLOY 825

200 < FBHT <= 250 C Cl- > 50000 ppm 25 % Cr INCONEL 718 INCOLOY 825

FBHT<= 250 C Cl- > 50000 ppm 28 % Cr INCOLOY- 825 INCONEL 718

FBHT < = 65 C AISI 41XX 22 HRC max

10-2

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pCO2 (atm)

151

10-1

1

10 100 pH2S (atm)

Figure 6.F - DHE Material Selection Diagram

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152

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ORDERING SPECIFICATIONS

When ordering tubulars for sour service, the following specifications should be included, in addition to those given in the above table. 1) 2) 3) 4) 5)

6) 7)

Downgraded grade N80, P105 or P110 tubulars are not acceptable for orders for J55 or K55 casing. The couplings must have the same heat treatment as the pipe body. The pipe must be tested to the alternative test pressure pressure (see API Bulletins 5A and 5AC). Cold die stamping is prohibited, all markings must be paint stencilled or hot die stamped. Three copies of the report providing the ladle analysis of each heat used in the manufacture of the goods shipped, together with all the check analyses performed, must be submitted. Three copies of a report showing the physical properties of the goods supplied and the results of hardness tests (Refer to step 3 above) must be submitted. Shell modified API thread compound must be used.

Note: ote:

Recom Reco mmenda endati tion ons s for for cas casing ing to be used used for for sour sour servi ervice ce must ust be specified according to the API 5CT for restricted yield strength casings.

The casing should also meet the following criteria:

• •

The steel used in the manufacture of the casing should have been quenched and tempered. (This treatment is superior to tubulars heated/treated by other methods, e.g. normalising and tempering). All sour service casing should be inspected using non-destructive testing or impact tests only, as per API Specification 5CT.

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TUBING DESIGN

7.1.

POLICIES

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All completion tubing strings will have tubing movement calculations conducted to ascertain the maximum load applied to the string and/or completion tubing movement to be catered for in the completion design. All tubing strings should be designed for stress, preferably using an appropriate up to date computer programme. Currently Eni-Agip Division and Affiliates recommended programme is the Enertech WS-Tube programme to the latest version. A safety factor (SF) of 1.25 applies to the ratio of the calculated stress in a string to the minimum yield yield strength of the selected tubing in carbon steels. A safety factor (SF) of 1.35 applies to the ratio of the calculated stress in a string to the minimum yield strength of the selected tubing of CRA materials.

If the stress SF is less than these limits, the calculation should be run again substituting, either a heavier weight or, a higher grade of pipe. Under some special conditions, the SFs may be reduced, refer to the criteria in section 7.10.2. Tubing size shall be determined by the reservoir engineers using IPR curves and Nodal analysis (Refer to section 5.6). 7.2.

THEORY

During completion tubing design process, it is necessary to calculate the variations in length for the stresses applied under load conditions. When these have been determined it will confirm the suitability of the selected tubing. Tubing movement occurs due to only two reasons:

• •

Temperature changes Change in pressure induced forces.

Movement can only occur if the tubing is free to move. If the tubing is not free to move and is anchored to a packer then stress will be subjected to the tubing string and packer. This relationship is fully explained in section 7.10 Stress Calculations. Tubing movement upwards (contraction) is assumed to be negative and downwards (lengthening) is positive. To fully understand these effects, it is first necessary to understand the properties of steels used in the manufacture of tubing.

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Mechanical Properties of Steel

Failure of a material or of a structural part may occur by fracture (e.g. the shattering of glass), yield, wear, corrosion, and other causes. These failures are failures of the material. Buckling may cause failure of the part without any fracture of the material. As load is applied, deformation takes place before any final fracture occurs. With all solid materials, some deformation may be sustained without permanent deformation, i.e., the material behaves elastically. Beyond the elastic limit, the elastic deformation is accompanied by varying amounts of plastic, or permanent, deformation. If a material sustains large amounts of plastic deformation before final fracture, it is classed as a ductile material, and if fracture occurs with little or no plastic deformation, the material is classed as brittle. Tests of materials may be conducted in many different ways, such as by torsion, compression and shear, but the tension test is the most common and is qualitatively characteristic of all the other types of tests. The action of a material under the gradually increasing extension in the tension test is usually represented by plotting apparent stress (the total load divided by the original cross-sectional area of the test piece) as ordinates against the apparent strain (elongation between two gauge points marked on the test piece divided by the original gauge length) as abscissae. A typical curve for steel is shown in figure 7.a. In this, the elastic deformation is approximately a straight line as called for by Hooke's Law, and the slope of this line, or the ratio of stress to strain within the elastic range, is the modulus of elasticity E, sometimes called Young's Modulus. This gives rise to Poisson’s Ratio, both are explained in figure 7.b.

Figure 7.A - Stress-Strain Curve for Tubing Steel

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Beyond the elastic limit, permanent or plastic strain occurs. If the stress is released in the region between the elastic limit and the yield strength; see figure 7.a, the material will contract along a line generally nearly straight and parallel to the original elastic line, leaving a permanent set.

Figure 7.B - Deformation Deformation Constants for Tubing Steel

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In steels, a curious phenomenon occurs after the elastic limit, known as yielding. This gives rise to a dip in the general curve followed by a period of deformation at approximately constant load. The maximum stress reached in this region is called the upper yield point and the lower part of the yielding region the lower yield point. In the harder and stronger steels, and under certain conditions of temperature, the yielding phenomenon is less prominent and is correspondingly harder to measure. In materials that do not exhibit a marked yield point, it is customary to measure a yield strength. This is arbitrarily defined as the stress at which the material has a specified permanent set (the value of 0.2% is widely accepted in the industry). For steels used in the manufacturing of tubular goods, API specifies the yield strength as the tensile strength required to produce a total elongation of 0.5% to 0.6% of the gauge length. Similar arbitrary rules are followed with regard to the elastic limit in commercial practice. Instead of determining the stress up to which there is no permanent set, as required by definition, it is customary to designate the end of the straight portion of the curve (by definition the proportional limit) as the elastic limit. Careful practice qualifies this by designating it the proportional elastic limit. As extension continues beyond yielding, the material becomes stronger causing a rise of the curve, but at the same time the cross-sectional area of the specimen becomes less as it is drawn out. This loss of area weakens the specimen so that the curve reaches a maximum and then falls off until final fracture occurs. The stress at the maximum point is called the tensile strength or the ultimate strength of the material and is its most often quoted property. The mechanical and chemical properties of casing, tubing and drill pipe are laid down in API specification of further specs. 5CT which is a combination of former specs. 5A, 5AC, 5AX and 5AQ - Casing and Tubing requirements. Depending on the type or grade, minimum requirements are laid down for the mechanical properties, and in the case of the yield point even maximum requirements (except for H-40). The denominations of the different grades are based on the minimum yield strength, e.g.: H-40 - min. yield strength 40,000 psi. J-55 - min. yield strength 55,000 psi. L-80 - min. yield strength 80,000 psi. Others are shown in figure 7.c. The lines indicating equivalent hardness of 22 and 23 Rc indicates the tolerances for use of the materials in H2S conditions according to NACE which is fully described in section 7.9.4.

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Figure 7.C - Strengths of Various Grades of Steel

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Temperature

Temperature changes cause expansion and contraction in metals which is a significant factor in tubing strings. All metals have a particular expansion rate which is termed the ‘Coefficient of thermal expansion’. For a given volume, an object will expand or contract through temperature change by the Co-efficient of thermal expansion for the type of material. -6

The co-efficient of liner expansion for tubular steels is usually 6.9 x 10 in/in/F°. 7.2.3.

Tubing Movement/Stress Movement/Stress Relationship Relationship

Steel tubing, as seen in the previous section 7.2.2 will expand or contract due to changes in temperature or pressure induced forces. If the tubing is free to move then the calculations will determine the maximum expansion or contraction which needs to be catered for by the utilisation of a tubing movement compensation system such as a packer and seal unit, a PBR, ELTSR or a travel joint depending on which type of packer system is utilised. If the tubing is attached to a packer, then the tubing is unable to move as it can in the free movement scenario and, in this case, changes in tubing stress will be exerted. This may increase or decrease the stress already exerted to the tubing when it was installed, which is the ‘initial’ ‘initial’ tubing condition. All subsequent changes in temperature or pressure induced forces are calculated form this initial condition. There are three methods in which tubing is connected to the packer: a)

Tubing is fully free to move either way.

b)

The tubing is positioned where it is fully free to move upwards but its its downward movement is restricted and stress applied to the packer.

c)

The tubing is connected to the packer by being threaded to, or latched to, the packer

Further explanation of these three modes are explained below. a)

Free Movement Movement

The tubing is free to move fully upwards or downwards using the packer bore with a seal assembly, a PBR, a TSR or travel joint (Refer to figure 7.d below). Calculations must be conducted to establish the full tubing movement in order that the length of tubing movement device can be determined. These devices are usually available in 10ft stroke lengths or multiples of 10ft, i.e. 10ft, 20ft and 30ft. The movement determined by calculation should be used to select a device which accommodates this movement with a margin of error, e.g. with a calculated movement of + 6ft and - 3ft = total 9ft, a 20ft device should be selected as a 10ft device would not provide enough contingency for error, unless the movement was subsequently restricted as described in the next section.

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b)

159

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Limited Downward Movement

In this case the tubing is fully free to move upwards but is restricted in its downward movement (Refer to figure 7.e). This restricted downward movement results in further stress applied to the bottom of the tubing and, correspondingly to the packer. This additional stress will be calculated during the tubing movement calculations and must not exceed the stress limit for the tubing, otherwise permanent deformation will occur. c)

Anchored Tubing

In this case the tubing is anchored to the packer by being threaded to it (as in the case when using retrievable packers) or by using an anchoring device such as an Anchor Latch, Ratchet Latch, etc. (Refer to figure 7.f). When the tubing is anchored to the packer and movement is eliminated, it will result in increased tensional and compressive forces, hence increased stress in the tubing. This may be acceptable when temperature and pressure changes are not excessive. Similarly, the calculations will determine that the tubing stress limit is not exceeded.

Figure 7.D - Free Moving

Figure 7.E - Limited Movement

Figure 7.F - Anchored Tubing

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160

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WELL DATA.

The well data and parameters required (or already determined) to produce an accurate tubing movement/stress analysis and, hence, selection of a tubing are:

• • • • • • • • 7.3.1.

Casing design profile Casing programme contingency profile Tubing size from optimisation analysis Pressure gradient Temperature gradient Reservoir fluids specific gravities Completion fluid specific gravities Production/injection or stimulation forecast.

Casing Profile/Geometry

The planned casing design and contingency plans are required as they affect the tubing movement calculations (Refer to 4.1.1). Each casing or liner weight and corresponding length of section must be known to enable calculation. Deviation tables are also required. 7.3.2.

Tubing Data

The optimum tubing size, determined by nodal analysis conducted by the reservoir engineers, is required and is the basis of all the calculations. The tubing grade is selected in accordance to the criteria listed in section 6 to combat the effects of any corrosion from the well conditions. The tubing movement/stress calculations will then determine the tubing weight or any change in grade required to meet with the applied SF for stress. The well deviation is also important to determine the type of packer/tubing seal device and/or tubing movement device to ensure that, either, straight pull or torque can be applied to the tubing downhole at the packer depth overcoming any frictional drag. Once the tubing size, weight and grade is confirmed then the appropriate rated completion components can be specified in order that the purchasing department can prepare tender documents. 7.3.3.

Bottom-hole Bottom-hole Pressure

Accurate initial and prognosed future formation pressures both static and dynamic are fundamental to tubing movement/stress calculations. These pressures can be obtained from previous well exploration test data or appraisal well test reports. 7.3.4.

Temperatures (Static and Flowing)

Accurate well temperature data are vital in tubing movement/stress analysis as the temperature effect is usually the effect which causes the greatest tubing movement. The average temperature of each section of tubing and casing must be known or determined to input into the calculations. Similar to the pressure data, temperature data may be found from previous well test results.

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Reservoir Fluids

As described earlier, the constituents of the produced reservoir fluids will initially determine the material required for the tubing. This is subject to any corrosion inhibition methods which may be implemented. Particular importance should be paid to Hydrogen Sulphide, Carbon Dioxide and Chloride levels. In the presence of water and under certain temperature conditions, these corrosive agents can cause serious problems, therefore it is essential that a detailed corrosion study is completed to enable the choice of materials and/or inhibition procedures. If justified economically, the material chosen should combat the effects of corrosion, however if this choice is not economic and some corrosion inhibition process was suitable then this would be a fallback position. Future parameters must also be considered as water may rise and the GOR will change, therefore the materials should be chosen to last the planned life of the completion. 7.3.6.

Completion Completion Fluid

The completion fluid, usually a brine, is chosen for its compatibility with the formation and its fluids so as not to cause any formation damage. It should be selected to provide an overbalance at the top of the reservoir. It also must be selected for its stability over long time periods and not suffer from dehydration or deterioration. As the completion fluid (sometimes referred to as the packer fluid) will be left in the annulus, it should be suitably dosed with corrosion inhibitors and oxygen scavenger to prevent corrosion to the exposed tubulars and elastomers. The information required to make a considered selection may be obtained from the ADIS (Advanced Drilling Information System) database (which holds all the data regarding the drilling of the well), well tests carried out earlier and other sources which may be useful in the decision making process. 7.4.

PRESSURE INDU INDUCED CED FORCES

When a well is completed, either with a tubing seal unit in a packer bore or a tubing movement device, it will have completion fluid in both the tubing and the annulus, this is referred to as the initial condition. All subsequent conditions are calculated from this initial condition. These are three pressure induced effects which produce forces that moves the tubing. These effects are: a)

Piston effect.

b)

Buckling effect. effe ct.

c)

Ballooning effect. eff ect.

Each of these effects are addressed in this section.

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Piston Effect

Tubing, when run in a well must first withstand the load of its own weight which may be a significant factor especially in deep wells. This tensile load is greatest in the joint immediately below the tubing hanger. The tubing is run into a completion fluid with equivalent fluid density inside and outside the tubing which results in a reduction of the load due to buoyancy. If there is an alteration from this initial condition causing a change in pressure forces across the packer seal unit then a piston effect is caused. This will alter the tensile load on the top and bottom of the tubing. The change in length due to these alterations is calculated from Hooks Law: Where E is the modulus of elasticity (sometimes referred to as a Young’s Modulus formula). The force (F) change is caused by the change in piston force from the initial conditions created by a change in pressure in the annulus or tubing at the packer. 7.7 and figure 7.h illustrate this piston force for two cases, tubing larger than the packer bore, and tubing smaller than the packer bore. The formula in each case is the same:

∆ L1 = −

 L  EAs

F 

Eq. 7.A

Substituting for F, the equation becomes:

∆ L1 = −

 L  EAs

[( Ap −  A1) ∆P1 − ( Ap −  Ao ) ∆Po]

where: L E  As  Ap  Ai  Ao  ∆Pi  ∆Po 

= = = = = = = =

Leng Length th of the the tub tubiing stri string ng to the the pac packe kerr dept depth h (ins (ins)) Young’s Modulus of El Elasticity (psi) 2 Cross sectional area of tubing (ins ) 2 Area of the packer bore (ins ) 2 Area of the tubing ID (ins ) 2 Area of the tubing OD (ins ) Chan hange in in tu tubin bing pr pressure at at the the pac packer (p (psi) Chan hange in in ann annu ulus pr press essure ure at at the the packer (p (psi)

Eq. 7.B

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Ao

Ao

Ai

Ai

r

Ap

0

r

Po

Pi

Figure 7.G - Packer Bore Larger Than Tubing OD 7.4.2.

163

Po

Ap

Pi

Figure 7.H - Packer Bore Smaller Than Tubing OD

Buckling Effect

Helical buckling is initiated by compressive force acting on the bottom of the tubing and is the formation of helical spirals in the tubing string. The helix shown in figure 7.i has a variable pitch as the compressive force is progressively lowered by the weight of the pipe hanging below. The buckling effect is greater when pressure differential is applied across the pipe. Unless the tubing string is short or the compressive force is exceedingly high, some of the tubing will be buckled and the rest straight. The exact point between the buckled and straight sections is the ‘neutral point’ (Refer to figure 7.i). The neutral point can be calculated from the following:

n=

F w

where: W Wi Wo

= = =

Ws + Wi - Wo Ai x Weight of fluid inside the tubing Ao x Weight of fluid outside outside the tubing

Eq. 7.C

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Figure 7.I - Neutral Point

When the neutral point is within the tubing length (and so the helix can fully develop), the length reduction due to helical buckling (Refer to figure 7.i) can be calculated by the following formula:

∆ L2 = − where:  I  =

π ( D 4

− d 4 )

64

2

2

F  r 

8  E  I  w

Eq. 7.D

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∆L2 Figure 7.J - Helical Buckling Buckling

If the tubing is very short (as happens for example on selective type completions between two packer’s) all the string may be affected by buckling and there is no neutral point. In this case, the length reduction due to the buckling effect is dependant upon the entire length of the string and can be calculated by the following formula:

n>L

∆ L2 = −

F 2 r 2  Lw  

2 − 8 EIw  F   

 Lw  

  F   

Eq. 7.E

As seen, the formulae for both piston effect and helicoidal buckling above has so far used F, i.e. the change in the piston force acting on the bottom of the tubing. However, in order to complete the understanding of the effects which lead to variations in length due to buckling, we must also consider the effect caused by pressure differential across a pipe. If the internal pressure in a pipe is greater than the external pressure, the tube remains straight only if it has an axially symmetric cross-section with no deformation to change its shape. This configuration is unstable and any distortion can lead immediately to a stable equilibrium condition which is helicoidal buckling. Helicoidal buckling is caused by the effect of the pressure which acts on the lateral surface of the pipe wall as the convex surface of the bend in a greater force is larger than the concave surface (Refer to figure 7.k). The internal pressure will therefore exert a greater force on the convex side of the helix, than that exerted on the concave section of the same bend. The resulting force will, therefore, create the helicoidal buckling configuration. The same occurs when the stable external pressure is greater than the internal pressure also resulting in helical buckling.

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Moreover, the effect of the external pressure on the tubing lateral surfaces is equivalent to a tensile force applied at the tubing bottom of: F  f 

 I 

F  f 

 II 

=  Ai Pi

Eq. 7.F

= − Ao Po

Eq. 7.G

R

Po

R

Po

Pi

Internal pressure

Pi

External pressure

Figure 7.K - Pressure Induced Helical Buckling Effect

From this it can be concluded that the effect of the internal pressure on the tubing lateral surfaces is equivalent to a compressive force applied at the bottom of the tubing. I

II

Therefore the tubing will be buckled by the piston force and by the sum of F f and Ff . The fictitious force Ff is obtained from the sum of the three elements: F  f 

= F  f   I  + F  f   II  + F a

Eq. 7.H

by substitution: F  f 

=  A p (Pi − Po )

Eq. 7.I

If Ff is greater than zero it will cause helical buckling and hence, if it is less than zero there is no deformation. It is however important to relate that the only force actually applied at the bottom of the tubing is the piston force, while the fictitious force is used only to calculate the buckling effect.

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It should be remembered that, to calculate the variations in length, the variations of the forces compared to initial conditions must be calculated. Therefore, to sum up:

• •

in the ∆L1 (Hooke’s law), the variation of the piston force F a must be used; in the ∆L2 (buckling), the variation of the fictitious force F f must be used when this is positive, otherwise, being a tensile force, it cannot buckle the string and ∆L2 = 0. The theory above was developed considering P i = Po in the initial conditions, it thus follows that the Ff is equal to zero and that the variation of fictitious force ∆Ff is therefore equal to the final fictitious force. 7.4.3.

Ballooning Effect

The third element which changes the length of a string, due to the changes to internal and external pressure, is caused by ballooning. This effect occurs when ∆P = Pi - P o is positive and tends to swell the tubing which, contracts axially or shortens (Refer to figure 7.m). On the other hand, when ∆P = Pi - P o is negative, the tubing is squeezed and, expands axially or elongates. This is termed reverse ballooning (Refer to figure 7.l). The normally used simplified formula to calculate the ballooning or reverse ballooning effect is:

2ν  ∆Pim −  R 2 ∆Pom  L ∆ L3 = −  E   R 2 − 1

Eq. 7.J

In this the average internal and external pressure variations are defined by the formulae:

∆Pim =

P  P − i  final i initial ( ) ( )   tophole

+  Pi ( final ) − Pi (initial )    bottomhole 2 Eq. 7.K

∆Pom =

P  P  P P − + − o  final o initial o  final o initial ( ) ( ) ( ) ( )   tophole   bottomhole 2 Eq. 7.L

Again this is developed from Hooke’s law using Young’s Modulus of elasticity (already used in the piston and buckling effect) and Poisson’ ratio. Poisson’s ratio v as earlier ea rlier expressed is: V  =

∆t  / t  ∆ L /  L

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0

Figure 7.M - Ballooning

Temperature Effect

The final effect considered when calculating tubing length variations, is the temperature effect which usually induces the largest movement. During a well operation, e.g. stimulation, the temperature of the tubing may be much less than that in, either, the initial or flow rate conditions. During well stimulations, significant quantities of fluids are pumped through the tubing at ambient surface temperature which may change the temperature of the tubing by several degrees. The formula used to calculate the change of length due to temperature effect is:

∆ L4 = α  ∆T  M   L Eq. 7.M

where the average temperature variation in the string can be calculated as follows:

∆T  M  =

T  final

− T initial

tophole

+ 2

T  final

− T initial

bottomhole

. Eq. 7.N

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In the formula α represents the material’s coefficient of thermal expansion. For steel this value is: in/ in/° °F. α  = 6.9 x 10-6 in/in/ figure 7.n shows typical geothermal temperature gradients during both stimulation and production conditions. It can be seen that the temperature variations to which the tubing is subjected may cause considerable changes to its length.

0

100

200

300 T (°F)

PRODUCTION

2500

5000

GEOTHERMAL

INJECTION

7500 D feet Figure 7.N - Typical Geothermal Gradients 7.5.

EVALUATION OF TOTAL TOT AL TUBING MOVEMENT

The sum of the length changes obtained from the changes in pressure induced forces and temperature effects, gives the total shift of the bottom end of the string at the packer depth where it is free to move in the packer-bore. This sum is calculated:

∆ Ltot  = ∆ L1 + ∆ L2 + ∆ L3 + ∆L4 Eq. 7.O

With free moving packer/tubing seals systems, the calculations are made for the selection of an appropriate length of seal assembly, PBR or ELTSR with anchored packer/tubing systems, this same calculation can be made to select the length of tubing movement devices such as telescopic or expansion joints. However, if no movement is converted to stress in the tubing, the resultant is stress on the packer (Refer to section 7.6).

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ANCHORED ANCH ORED TUBING

In some completions the tubing is firmly fixed to the packer, preventing any movement of the string when well conditions vary (figure 7.o). In this situation the tubing-packer forces generated by the presence of the anchoring must be determined so as to be able to confirm if the tubing-packer anchoring system and the packer have sufficient strength to safely withstand all the forces exerted. Moreover, once this force is known, the load on the tubing can be calculated to check if the completion components have sufficient strength.

Figure 7.O - Tubing Anchored To Packer

The tubing-packer force can be calculated by initially assuming that the tubing is free to move in the packer seal-bore and it is possible to calculate the final total length change of the tubing under pressure and temperature variations of all conditions. Subsequently, the force needed to re-anchor the tubing to the packer can be determined. To understand this concept better, consider figure 7.p where it is presumed that the tubing can move away from its anchored condition while maintaining the seal with the packer and that the tubing undergoes only ∆L4 contraction caused by the temperature effect. Since no force is applied at the end of the tubing which could cause buckling, all the movement is linear and to restore to the tubing’s real anchored position, it is sufficient to impose a ∆L4 elongation by applying a force F P which is obtained from Hooke’s law:

∆ L = −

FL  EAs

⇒

F P

= −∆ L4

 EAs  L Eq. 7.P

However, in general the problem of identifying the tubing/packer reaction is not linear due to the helical buckling effect and so, it is possible to use a graphical approach.

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The first step is to plot the characteristic strength/length variation of the system. This curve, shown in figure 7.p is determined by the size of tubing, on the material, radial distance between the tubing OD and casing ID and on the fluids in the well. This can be plotted using the following formulae:

∆ L = − ∆ L = −

FL

( for F < 0 )

 EAs FL  EAs

−

2

2

F  r 

8 EIw

( for F > 0 ) Eq. 7.Q

The second step is to identify, on the curve, the tubing representative point in the well when it is subjected to the fictitious force, even when this is negative. On the curve given in figure 7.q this condition is identified by intersection point (F f, ∆Lf). Indeed, if a force of Ff, was applied at the end of the tubing, the cause of the buckling would be eliminated and the neutral point would return to the bottom in the tubing. The origin of the axis moves to the point found in this way (Ff ,∆Lf) and the diagram obtained has a total length variation of ∆LP = -∆ltot, so to position the tubing in the packer after contracting the string must be elongated accordingly. As shown in figure 7.q the F p force, transferred between the tubing and packer, is then identified.

∆L4 Fp

∆L

∆ L4 Fp

F

Figure 7.P - Graphical Representation Of Movement

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∆Lp Fp

∆L

Fp

∆Lp

∆Lf 

F

Ff 

Figure 7.Q - Graphical Representation of Force 7.6.1.

Tubing Permitting Limited Motion

Another method which may be used in some types of completions is that the tubing is fully or partially limited in downhole movement. In this method, after the packer is set, some of the weight of the string is set down on the packer, putting the tubing into compression or slackened-off (Refer to figure 7.r).

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Figure 7.R - Limited Downward Movement Movement

The shortening of the string caused by this, ∆Pso, makes it possible to limit the length variations of the string, for example, during an injection operation, therefore, ∆Ltot, i.e. the total length variation calculated as the sum of the above described effects, is decreased by ∆Lso. The ∆Lso value is determined using the following formula:

∆ Lso = −

F so  L  E  As

−

F so2 r 2

8  E  I  w Eq. 7.R

where: F so 

=

slack-off for force re released on on th the pa packer.

With this type of anchoring it is, therefore, possible to limit the movements of the tubing with respect to the packer and consequently the length of the packer seal-assembly. If an anchored type constraint is considered then the tubing-packer force with respect to the anchored tubing can be reduced, e.g. in an injection operation. In practice, applying slack-off is the same as moving the packer upwards by ∆Lso, compressing the string and thus causing part of the length variation which would occur in any case at a later stage due to the effects described above. The same considerations can be made if ∆Ltot < 0 during the operation while, on the other hand, any elongation of the string would be prevented, causing a force on the packer which would be equal to that of the slack-off amount.

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Packer Setting

A particular problem arises in tubing tied to packer completions when using hydraulic set packers, as pressure is applied to the tubing to set the packer, it changes the length of the tubing during the setting process. This in turn places stress in the tubing after the packer is set and the pressure is bled off. This stress needs to be taken into account to determine the total stress applied to the tubing. Hydraulic packers are set by plugging the tubing below the packer either by dropping a setting ball onto a shear out ball seat, or by installing a plug with wireline. The formulae for determine this tubing length change are:

∆ L1 = − ∆ L3 = −

∆F a L

(Hooke’s law)

 EAs

∆Pim  L  E   R 2 − 1

2ν 

(ballooning)

where:

∆F a = − Ai ∆Pi 7.7.

and

∆Pim=∆Pi

TUBING LOAD CONDITIONS

The load conditions of the tubing string during the well’s life causes stresses through the pressure, temperature and mechanical loads for each condition imposed. It is therefore obvious why, when selecting the type of tubing for a completion, it is essential to identify exactly what operations will be carried out in future to determine the consequent loads and thus the associated load conditions. A manual or computer programme is then used to calculate and then ascertain whether the given tubing is able to withstand the maximum load with an acceptable safety level. The operations normally carried out on a well for which the string control is necessary are illustrated below. These should be seen only as an example of load conditions as each case must be addressed individually as planned operations may vary. It is important, in any case, to analyse the characteristics of each operation in order to be able to identify the heavier loads which may be imposed. 7.7.1.

Pressure Testing

The very first load condition experienced during and after the installation of the completion string is pressure testing. This involves applying predetermined test pressures to both the tubing and annulus. These pressures may be applied more than once during the installation operation. During the time taken to install the tubing, the completion will have warmed up to ambient well conditions, therefore the only load applied is the pressure induced forces of piston effect buckling and ballooning. However, the designed test pressures should be equal to or greater than any other subsequent pressures applied to the completion so the magnitude is high. This may be of particular concern when using large bore tubing movement devices as the forces generated by the test pressure are greater than packer tubing seal arrangements.

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Acid Aci d Stimulation Stimulation

Acid jobs are carried out to remove formation damage caused during drilling by the invasion of fluids and cuttings or to stimulate the formation by improving permeability. This operation is carried out by pumping a predetermined quantity of acid down the tubing to the formation at set pressures and flow rates. From the point of view of the stresses exerted on the tubing string, the maximum pressure able to be applied at the well head must be considered in order to determine the rate of acid which can be applied, together with the temperature variations caused by the injection of colder fluid. It may be necessary in some cases, to reduce the loads on the tubing by preheating the acid in order to limit the thermal expansion and pressurising the annulus to reduce the tubing ballooning effect. Friction reducers may also be used to increase flow at the same wellhead pressure, and decreasing the bottom hole pressure thus reducing the load. It is important to monitor the pressure and temperature trends during the operation as the acid rate will probably increase due to the effect of the acid on the formation. This may lead to greater cooling down of the tubing with reduced pressures. figure 7.s shows the pressure and temperature trends required to be known so as to ensure stress control of the string, according to the classical Lubinsky theory. Other data are often needed for more complex calculations, using computer programmes, which, in Eni-Agip Division and Affiliates case are in-house software which allows reproduction of the correct temperature trend. 7.7.3.

Fracturing

Fracturing involves the propagation of fractures in the formation for the improvement of productivity of hydrocarbons. These fractures reach from the well bore deep into reservoir and allows better drainage. To carry out fracturing, the formation must be pressurised until one (or more) fractures are created. This entails obtaining in advance the injection parameters from various injectivity tests with increasing flow rates. The calculated flow rate is applied during the operation and the pressure trend (which usually decreases when the fracture is created due to the reduction of load losses in the formation) is monitored. With regard to the stresses on the string similar to acid stimulations, it is important to assess the drop in temperature caused by the injection of colder fluid which, is carried out at high flow rates even though of short duration. The pressures which can be attained, especially during the early injection stage, are higher than that during acid jobs. At times during these early stages, in order to exceed the fracturing gradient, the maximum allowable pressure for some well head equipment may be reached. This equipment must therefore be protected using special isolating tools or protection sleeves. To check the string design is suitable, the pressure and temperature trends can be plotted as shown by the previous example of the acid stimulation (figure 7.s), selecting the end of the operation as the final conditions but with a well head pressure equal to the maximum estimated.

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If during the initial stages of the operation, a significant break-down is forecast (by a marked reduction of pressure when the fracture is opened up in the formation). The latter condition may be too conservative, therefore two conditions should be checked; the first with high pressures without temperature variations, and the second with marked temperature variations and lower pressures.

0

100

200

300 T °F)

0

INITIAL CSG AND TBG - FINAL CSG

2500

FINAL TBG

5000

7500 D feet)

0

5000

10000

0 FINAL CSG

15000 P

si)

FINAL TBG

2500

5000 INITIAL TBG

INITIAL CSG

7500 D feet)

Figure 7.S - Pressure and Temperature Trends During Fracturing

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Flowing

In this case it is not an operation carried out on the well but the normal flowing load conditions to which the string is being subjected. It is therefore very important to establish, or at least approximate, the pressure and temperature profiles during the life of the well. Different production situations will occur which cause changing load conditions; e.g. temperature differences between the beginning and end of the productive life or the need to increase or decrease the flow rate for reasons external to the well. Compared to the initial condition, the string undergoes temperature increases which cause elongation in the string. The resulting compressive forces may lead to the buckling phenomena and even cause the tubing to exceed its elastic limit. As shown in the diagrams of figure 7.t and figure 7.u, which give the pressure and temperature bottom hole trends as a function of the depth at production start up and when the reservoir is depleted, external pressure may be greater than internal pressure, making it necessary to ensure a collapse control of some sections. 7.7.5.

Shut-In

Once a well is in production, it is necessary to interrupt production for maintenance or in order to take some data measurements. This shut-in operation involves closing the well during which the well head pressure increases because the reservoir pressure rises to static condition, pressuring up the fluids in the tubing. This load condition is considered critical as, at the moment of shut-in, the temperature of the string does not vary greatly due to the thermal inertia of the well. The situation is now similar to that during production but with well head pressures which are greater and hence increase the stresses on the string. figure 7.u shows typical pressure and temperature trends after a shut-in.

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0

178

100

0

200

300 T (°F)

0

2500

FINAL TBG

5000 INITIAL CSG E TBG - FINAL CSG

7500 D feet

0

5000

10000

0

15000 P

si

FINAL TBG

2500

INITIAL TBG

5000 INITIAL CSG - FINAL CSG

7500 D (feet) Figure 7.T - Pressure and Temperature Trends in Normal Production Conditions

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Figure 7.U - Pressure and Temperature Trends in Depleted Reservoir Production Conditions

0

100

200

0

300 T °F

2500

FINAL TBG

5000 INITIAL CSG E TBG - FINAL CSG

7500 D (feet)

0

5000

10000

0 FINAL TBG

2500

INITIAL TBG

5000 INITIAL CSG - FINAL CSG

7500 D (feet)

15000 P

si

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180

100

0

200

300 T (°F)

0

2500

FINAL TBG

5000 INITIAL CSG AND TBG - CSG FINAL

7500 D (feet)

0

5000

10000

0

15000 P ( si)

FINAL TBG

2500

INITIAL TBG

5000 INITIAL CSG - FINAL CSG

7500 D (feet) Figure 7.V - Pressure and Temperature T emperature Trends After Shut-In

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Load Condition Summary

The operations described above were chosen because they are the most common and show which aspects of an operation must be known in order to determine which loads will have to be considered to verify string design. As shown in the examples above, it is important to be able to plot the pressure and temperature trends of the casing and tubing on the two pressure/depth and temperature/  depth diagrams for the moment before the packer is set (initial conditions) and at the end of this operation (final condition) or, in any case, during the stage considered most critical as regards the loads applied. Using the above diagrams, and knowing the completion configuration, the relative loads on the sections of the string can be calculated, generally this is greatest in the section above the packer and below the well head. If the string is tapered or has one, or more, intermediate packers, it will be necessary during the control stage to know the pressure and temperature data of all the packers and of the tubing cross-section variations and is good practice to plot these data on diagrams. 7.8.

TUBING TUBING SELECTION

The tubing string selection procedure and subsequent stress analysis is fundamental to the completion design process as it is during these two stages, that the optimum solution is found through a sequence of approximations. By using an iterative method, i.e. by choosing and verifying the various possibilities, the correct safety factor for all the calculated load conditions expected during the life of the well, can be obtained. The Eni-Agip Division and Affiliates approach to choosing the tubing string is similar to that followed when designing any other mechanical part. A draft design is considered based on the expected well conditions and then this design is checked to obtain the safety factor(s). Alterations are then made to the draft completion until the ideal safety factor, which may differ depending on the local environmental conditions and on some parameters discussed below, is reached. Since the economic factor plays a primary role of importance when selecting a completion, it is necessary to assess all the various possible solutions. A typical example is that of wells with the presence of corrosive agents where either strings and down hole equipment can be made in Corrosion Resistant Alloy (CRA) or carbon steel with inhibitors injected downhole can be used. In both cases the problem of completing the well is solved but it is necessary to verify both cost and whether it is better to use on CRA, avoiding future workovers or if it is more economical to use carbon steel with an inhibition system and scheduled workovers.

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Critical Factors

The main factors driving the choice of the string are described below. Taking into consideration the well conditions, it is then possible to identify the optimum mechanical solutions. Materials

The choice of material for the tubing string depends mainly on the well environment, in terms of all the mechanical stresses and corrosivity of the fluids. In general, the ideal material is determined by the results of corrosion studies carried out prior to the tubing design stage, especially when the severity of the conditions suggest the use of expensive CRA materials (Refer to section 6). With regard to corrosion studies, it is always necessary to determine, the exact quantities of H2S, CO2, chlorides and water from production tests and to enter these data into an expert system, or for a quicker choice, using the engineering diagrams supplied by manufacturers. However, this method does not provide a solution to using carbon steel in conjunction with an inhibition system. In this case, it is best to base the choice on an appropriate corrosion study which takes into account many other parameters, e.g. thickness of the corrosion product, economics, frequency of workovers, etc. Once the choice of materials has been identified, it will be necessary to take into consideration their mechanical properties to ensure that a suitable factor can be verified in the subsequent stress analysis stage. Indeed, to complete a well with the presence of corrosive agents (H 2S and/or CO2) the use carbon steel with controlled hardness and/or martensitic steel, is often sufficient though these only reach a maximum grade of T95 (95 ksi yield) therefore do not always meet with stress requirements in high pressures and great depth. When CRA steels are used (which must be cold worked in order to obtain the required mechanical characteristics), the possibility of anisotropies must be checked into as they generally imply a lower compressive yield load than tensile yield load and corresponding reductions for their use at high temperatures. The presence of residual tension may induce stress corrosion and over-stressing problems which must also be taken into consideration. 7.8.2.

Tubing Size And Weight

One of the main elements of the completion string design process, is the choice of the size, wall thickness and grade of tubing which is optimum to requirements, outlined below. The inside and outside diameter of the tubing, and if the string has more than one size of tubing as in a tapered string, the length of each section needs to be determined at this point. Given that the dimensions of the tubing and components of the string (safety valves, landing nipples, etc.) must fit inside the production casing and/or liner, it is essential to establish the size in order to find out if it impacts on the casing design. Note: Note:

It is is vital vital that that any detriment detrimental al impact impact caused caused by the the casing casing program programme me is is discussed with the drilling engineers to solve any problems, whether this entails changes to either the casing programme or the completion design.

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The first indications of tubing size obtained is from tubing inflow performance analysis. These studies can generally be completed quickly using Eni-Agip Division and Affiliates software which directly provides the diameters of tubing for the expected flow rates and projected rates, which take into account the type of fluid, surface pressures, bottom hole pressures and other parameters. Calculation of the tubing inflow performance is very complicated and time consuming in most cases and is not covered in this manual. Once the projected size of the tubing is established for the required flow rate then in gas, or gas condensate wells, it is necessary to calculate the velocities in the string during production. This rate must be lower than the rate at which erosion occurs. These threshold velocities can be found in API RP 14E. The most important value to be decided on the selected tubing is its mechanical strength. As explained in the following section, the loads resulting from the various load conditions (acid jobs, production, etc.) applied to the selected string, the safety factor under these loads against the yield strength are calculated. Once this calculation has been made, it may be necessary to increase the weight or grade because the string is too weak. In some particular situations non-traditional solutions must be chosen as some parameters, such as cost, limit the choices. In the case of a very expensive super austenitic steel string for example, it may be more appropriate to choose more structurally efficient solutions which use a tapered string with different diameters thus reducing the amount of material needed and therefore the cost. Wells in which hydrocarbons containing corrosive agents are produced are sometimes completed using carbon steel and it is accepted that a certain amount of the material will be lost through corrosion during the life of the well. The strings of these wells, which generally will be equipped with a corrosion inhibitor injection system, should therefore have added thickness so as to have sufficient material to last until the scheduled workover. The two cases; i.e. the new string (maximum thickness, maximum weight) and the workover stage (minimum thickness, minimum weight) must both be taken into consideration when calculating the string’s stress resistance. It is prudent in such cases to reduce through tubing interventions which knock off the corrosion exposing fresh material and, hence, faster wall thickness reduction. When choosing the thickness of the tubing forming the string, it is useful to consider the thickness tolerance adopted by the manufacturer of the selected tubing. API standards for carbon steels define a 12.5% eccentricity tolerance which means one point on the tubing’s circumference probably has less thickness. This value for CRA tubing’s is often only 10%. which provides a better safety factor under similar conditions. Another reduction of thickness which must be taken into account on used tubing, may be due to repairs, by grinding, carried out to remove tong marks. The above factors can often lead to a variety of solutions, so it is necessary to evaluate each one in order to obtain the most suitable solution in terms of cost, mechanical strength and practical feasibility.

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Anchoring Anchoring Systems

As illustrated earlier, the operations carried out during the life of a well cause movement of the tubing string which can depend on the type of tubing/packer seal system used between the bottom of the tubing and the packer, will generate different loads in the string will be generated. From figure 7.w, which shows the three most common types of packer/tubing systems, it is clear from this that the least severe system is where the tubing seal assembly is free to move in the packer bore. This system does, however, have some disadvantages which are often unacceptable such as dynamic seals. In very deep wells, with high pressures and temperatures the movements of the lower end of the tubing may reach several feet in magnitude and hence very long seal units would need to be used in the packer which brings related assembly and protection problems during running in. Another important problem of free tubing, is the continuous movement of the seal elastomers which may become damaged due to wear or from the debris deposited in the annulus above the packer. The best solution, due to the use of static seals, is systems to screw the tubing to the packer using a threaded connection on retrievable packer systems or to a tubing anchor (which allows the packer to be released when necessary) on permanent packer systems. This type of anchoring provides the solution to seal life, but leads to greater stressing of the tubing string. In preference, the free moving system is the first choice and if the loads it creates do not allow for a suitable safety factor during well operations are other systems considered.

Free Movement

Limited Downward Movement

Attached

Figure 7.W - Tubing/Packer Tubing/Pac ker Systems

The second preference is where downward tubing movement is restricted i.e. using a NoGo locator shoulder fitted above the seal assembly where it is positioned to prevent the elongation of the string while leaving it free to shorten. This will reduce movement of the packer seal assembly by eliminating downward movement and upward movement would only occur in certain limited lead conditions (stimulations or fracturing). This will extend seal life.

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TUBING CONNECTIONS

The Eni-Agip Division and Affiliates policy for tubing connections is that ‘the use of premium connections is mandatory’. In conjunction Eni-Agip Division and Affiliates also recommended that a premium connection be used for production casings and production liners, especially when the annulus is to be used for gas lift or an underbalance fluid is used as a completion fluid. 7.9.1.

Policy

• •

The use of premium connections for tubing is mandatory. The use of premium connections for production casing is advised but not mandatory.

The connections to be used shall be qualified according to the requirements as set in the Eni-Agip Division and Affiliates procedure ‘Connection Procedure Evaluation’. 7.9.2.

Class of Service

According to the specification STAP M-1-M 5006 ‘Connection Procedure Evaluation’, there are two service classes, I and II, termed Application Levels (AL). Application Level I applies to the most severe service conditions. To date three tubing connections have been qualified for the most severe conditions ALI. They are : Coupled Connections AMS 28 ( manufacturer Dalmine) Vam ACE ( manufacturer Vallourec and Sumitomo) Integral Connections Eni-Agip Division and Aff iliates A-DMS (Dual Metal Seal) Other connections like Hydril CS, PJD Dalmine and Antares MS have not yet been subjected to the complete qualification programme as per STAP M-1-M- 5006 or API 5C5. They have however been used successfully for years with good results. They may be used for all service condition condition where an Application Level II connection is required.

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Selection Criteria

The following are the selection criteria for connections used in different types of wells and operating conditions. Work string or well testing string: Integral AL1 connection shall be used Horizontal wells with Build up

≥ 20°/100 20°/100 feet: fee t:

Integral AL1 connection should be used Wells with TVD

≥ 4500m:

Integral AL1 connection shall be used Producing Oil And Gas Wells (TVD < 4500m) Criteria

Requirement

NACE

no

no

yes

yes

Close Proximity

yes

no

yes

no

Diff erential W P 0 - 4000 psi

AL II

AL II

AL I

AL II

Diff erential W P 4000 - 8000 psi

AL I

AL II (*)

AL I

AL I

Diff erential W P over 8000 psi

AL I

AL I

AL I

AL I

(*) For Gas Injection wells, AL I Table 7.A - Connection Specification S pecification Storage/Injection Gas Wells (TVD < 4500m) Criteria

Requirement

Diff erential W P 0 - 4000 psi

AL I

Diff erential W P 4000 - 8000 psi

AL II

Table 7.B - Connection Specification

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Water Injection Wells (TVD < 4500m) Criteria

Requirement

Diff erential W P 0 - 4000 psi

AL II

Diff erential W P 4000 - 8000 psi

AL II

Table 7.C - Connection Specification

A flow chart reaffirming the above is shown in figure 7.x. Note: Section 7.9.4 explains the NACE and Close Proximity definitions. Differential working pressure is the maximum differential pressure (internal and/or external) to which the production string is subjected during during the life of the well.

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Figure 7.X - Connection Application Application Level Selection Flow Chart

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NACE NA CE And Proximity Definitions NACE Requirement

This applies to the partial pressure of hydrogen sulphide (H 2S) in the produced fluid as defined by NACE Standard MR 01-75. Close Proximity

A proximity assessment should be prepared to consider the potential impact of an uncontrolled well flow condition on the life of personnel and the environment around the wellhead. The following list of criteria can be used for determining this potential risk. Other criteria for consideration should be included when necessary. 100ppm Radius of Exposure (ROE) of H 2S is greater than 50ft. from the wellhead and includes any part of a public area except a public road. Public area shall mean a dwelling, place of business, church, school, hospital, school bus stop, government building, a public road, all or any portion of a park, city, town, village, or other similar area that one can expect to be populated. Public road shall mean any federal, state, county or municipal street or road owned or maintained for public access or use. 500ppm ROE of H2S is greater than 50ft. from the wellhead and includes any part of a public area including a public road.

• • • • • • •

Well is located in any environmentally sensitive area such as parks, wildlife preserve, city limits, etc. Well is located within 150ft. of an open flame or fired equipment. Well is located within 50ft. of a public road (lease road excluded). Well is located in state waters. Well is located in or near inland navigable waters Well is located in or near surface domestic water supplies. Well is located within 350ft of any dwelling.

These conditions are recommended minimum considerations. It will be necessary to meet any other local regulatory requirements. Texas Railroad Commission Rules

The following information is taken from Texas Railroad Commission Rule 36: For determining the location of the 100ppm radius of exposure: X = [(1.589) (mole fraction H2S) (Q)] 0.6258 For determining the location of the 500ppm radius of exposure: X = [(0.4546) (mole fraction H2S) (Q)] 0.6258

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where: X = Radius of exposure in feet Q=

Maximum volume determined to be available for escape in cubic feet per day.

H2S =

Mole Mole fracti fraction on of hydroge hydrogen n sulphid sulphide e in the gaseous gaseous mixtur mixture e which which could could escape.

The volume used as the escape rate in determining the radius of exposure shall be that specified below, as is applicable: For the new wells in developed areas, the escape rate shall be determined by using the current adjusted open-flow rate of offset wells, or the field average current adjusted openflow rate, whichever is the larger. The escape rate used in determining the radius of exposure shall be corrected to standard o conditions of 14.65psia and 60 F. When a well is in an area where insufficient data exists to calculate a radius of exposure, but where hydrogen sulphide may be expected, a 100ppm radius of exposure equal to 3,000ft shall be assumed. 7.9.5.

CRA Connections

For steels with a high chrome content (>13%), there is a tendency to gall during make up. This requires special surface treatment in the connection’s pin and box. The anti-galling treatments (e.g. Bakertron or copper plating) is always applied to the couplings to ensure the utmost coating, hence protection. 7.9.6.

Connection Data

Data on tubing connections are available from API specifications and tables in industry handbooks. 7.10.

TUBING STRESS STRES S CALCULATIONS CALCULATIONS

The final stage of the completion string design is the calculation of stress in areas under the highest loads. After these calculations are made, it is possible to determine how close the stresses are to the material’s yield strength. At this point of the process all the possible elements needed for the design verification are available; i.e. information about the load conditions, the type of tubing and materials to be used to meet the requirements outlined in section 6.8. Using the calculation theory illustrated previously, it is possible to calculate the forces acting on the packer, Fp, and consequently, the fictitious and piston forces in the string sections. During the verification stage it may be seen that the loads on the string are unacceptably high. The string or load conditions or the tubing strength must therefore be altered until the calculation produces an appropriate safety factor (SF). Computer programmes are very useful in this phase as it is possible to make repeated calculations quickly with different parameters.

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7.10.1. Calculation Methods

Taking, as an example, the type of completion shown in figure 7.y, the sections where the string design must be verified are indicated by x-x at the well head and y-y at the downhole  just above the packer. For other types of completions, string design must be verified at all the appropriate sections where there are variations in diameter, have intermediate packers or other discontinuities. With reference to figure 7.y, the tables below summarise the forces acting on the sections of the string which will be used for the design verifications. The asterix distinguishes the forces calculated in a completion with the string anchored to the packer verses those calculated for a string free to move in the seal bore. Section Y-Y (Packer) Tubing-Packer Mode

Piston Forces

Fictitious Forces

Free tubing

F a  a 

F f f 

Tubing permitting limited motion and anchored

*

F a

= F a + F p

*

F  f 

= F  f  + F  p

Table 7.D - Forces at Y-Y

Section X-X (Well Head) Tubing-Packer Mode

Piston Forces

Free tubing

F a tp

Tubing permitting limited motion and anchored

F a tp

*

Fictitious Forces

= F a − ws L

F  f  tp

= F a* − ws L

F  f  tp

*

= F f  − wL = F f * − wL

Table 7.E - Forces at X-X

As can be seen, the forces at the well head coincide with those at the packer depth if L = 0. Therefore, to calculate forces on intermediate sections between the well head and packer depth, it is sufficient to use an intermediate length ‘l’ ( L > l > 0 ) measured from the packer, instead of ‘L’ of the previous formulae.

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X

X

Y

Y

0

Figure 7.Y - Example Completion #1

The piston forces obtained in this way are used to calculate the axial stress which is given by the expression:

σ a

=

F a  As

The fictitious force is used to calculate the axial stress caused by the tubing bending when helically buckled, it is given by the expression:

σ b therefore,

=  Dr  F  f  4 I 

σb is calculated only if the section of the string to be verified is buckled.

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Now all the factors needed to determine the equivalent stress σa, σb, Po and Pi are available, i.e. the stress which, by applying suitable criterion (for the materials used in the oil industry the most appropriate is Von Mises), allows comparison of the stresses due to the different effects in a particular section of the string against the material yield stress rating. In this case the equivalent force will be the greater of the two, calculated using the expression below, which gives the equivalent stresses in the outside and inside wall of the considered tubing section. 2

2

σ o

2 Pi − Po   Pi −  R Po   = 3 2   +  2 + σ a ± σ b     1 1 − −  R  R    

σ i

 R 2 (Pi − Po )  Pi −  R 2 Po σ b      = 3 + + ± σ   a 2 2   R    R − 1   R − 1 

2

2

As stated above, if the section to be calculated is buckled, both calculations must be made to determine the higher of the two values while, if there is no buckling σb = 0 and the greater stress is that in the inside wall, the equivalent stress is σeq = σi The higher of the stress values determined above will make it possible to obtain the SF of the string for the load conditions and the section considered:

SF =

σ sn σ eq

The SF must be greater than the minimum dictated by policy and listed in section 7.1 which gives the SF values to be used by Eni-Agip Division and Affiliates. 7.10.2. Safety Factor

A completion string’s safety factor is defined as the ratio between the yield stress and the maximum value of the stress obtained as described above. It, therefore, provides a quick reference parameter to evaluate the magnitude of the stresses present in the tubing compared to the maximum acceptable. To calculate the SF the yield limit values of the material are taken into consideration so that there is no permanent corkscrewing of the string which could jeopardise, even if only slightly, its functionality. The Eni-Agip Division and Affiliates policy is to apply different types of material due to their different mechanical behaviours and resistance to corrosion. Carbon and CRA Steels up to 13%Cr

The acceptable SF for these types of materials is:

1.25

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In each individual case the string design and stress analysis engineer may evaluate whether the acceptable SF can be lowered to 1.15 for some particular operations and for specific well conditions. (e.g. low pressure oil wells, economic decision not to use the next grade of tubing etc.). Cold Worked (CW) CRA Steels

The acceptable SF for these types of materials which include duplex, super-austenitic and Incoloy is:

1.35 Similarly, the engineer may evaluate whether, for some particular operations and for specific well conditions, the acceptable SF can be lowered to 1.20. The different SF’s between the carbon and CRA steels can be attributed to the different behaviour of these materials for stress values above the yield point. As stated previously, the SF is calculated using the yield point but also the collapse rating of the string. This is a dangerous situation which occurs at the breaking point. figure 7.z shows the stress/strain diagrams for the above two types of materials. As can be seen, apart from the yielding the cold worked materials reach breaking point soon after the yield point while the carbon steels maintain a greater plastic deformation margin before the breaking point. Furthermore, the cold worked materials retain residual stress so, from both the viewpoint of stress corrosion and mechanical strength, the SF should be slightly higher. It is, therefore, clear that a higher SF for Cold Worked materials is required in order to maintain the same safety factor relevant to the breaking points for the two types of materials.

Figure 7.Z - Stress/Strain Diagrams Diagrams

COLD WORKED

CARBON STEEL

σ

σ

r r sn

sn

= break breakin in poin pointt sn = ield point ε = elongation r

ε

ε

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The SF discussed up to this point is valid, if referred to only as in the condition of triaxial stress which, therefore, takes into consideration all the stress components to determine the σeq, from which it is possible to make a comparison with the yield load. Any other SFs, referred to, in a state of monoaxial stresses, cannot be compared in any way to those described in this manual because they take into consideration only one mode of loading. For example, tension tubing, if applied individually, causes a state of monoaxial stress. However, it would be incorrect to use the SF for tension alone because during the life of the well it will be subjected to a combination of stresses. 7.10.3. External Pressure Limit

During the productive life of a well, conditions may occur making it necessary to limit the external pressure on the string. One example is a well at the end of its productive life with less pressure in the tubing than in the annulus, due to the depletion in reservoir pressure. Another example is downhole pumps for artificial lifting and are operated by the power fluid pumped down the annulus, which require substantial differential operating pressures. Calculation of external pressure is carried out using the formulae supplied supplied by API Bulletin 5C3 which identifies four types of collapse at external pressure in relation to the D/t ratio and the Yp yield stress of the material. In fact the causes of collapse can range from material yield as in the case of pipes with a low D/t ratio, to the section’s elastic limit which occurs in thin-walled pipes. In order to use the API Bul 5C3 formulae, once D/t and Y p are known, the type of formula is chosen then the maximum withstandable pressure calculated. If an axial force is applied to the pipe as well as external pressure, the Y p value for use for calculations is adjusted using a special formula. 7.10.4. Packer Load Limits Limits

If the Fp force value transmitted by the string to the packer is known, it is possible to calculate this value under various well conditions. By evaluating the magnitude of this force and considering other factors such as the possibility of future recovery, the most suitable type of packer in relation to the completion type, can be determined. By using diagrams supplied by the manufacturer, it is possible to check whether well conditions come within the limits set by the packer rating. A typical diagram for packer force limits is shown in figure 7.aa. If the force exerted by the tubing on the packer (Fp = set-down, if negative, F p = tension, is positive) and the differential pressure above and below the packer (P o>Pi above, Po
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400    )   n   o    i   s   n   e    t    (

300

200    )

   E  s    C   d   n    R  a   s    O  u    F   o

100

   h    T    (

   )   n   w   o    d      t   e   s    (

Safety zone

0

-100

-200 -20

-10

0

10

20

(Thousands)

(above)

PRESSURE DIFF.

(below)

Figure 7.AA - Typical Packer Force Limit Diagram 7.10.5. Example Manual Calculation

As an example of applying the method detailed above, we can consider the single completion in the well shown in figure 7.bb. During a cement squeeze operation, the analysis of the possible packer/tubing configurations available in this set-up is free tubing to packer and fully anchored. This allows calculation of the variations in in length and thereafter the anchoring force in the packer. Data: 7

2

Tubing 2  / 8in 6.5lb/ft :

Ai = 4.68in 2 Ao = 6.49in 2 As = 1.81in R = 1.178 ws = 0.542lb/in 4 I = 1.61in σsn = 80,000psi

Casing 7in 32lb/ft:

ID = 6.094in r = 1.61in

Packer bore:

Dpb = 3.25in 2 Ap = 8.3in

Length of string:

L = 10,000ft = 120,000in

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Initial Conditions

Initially both the tubing and the annulus are filled with 30° API oil, while the temperature is 60°F at the well head and 200°F 200°F at the bottom bott om hole. figure f igure 7.cc shows sho ws the pressure and temperature variations against depth. It should be noted that t hat 30° API corresponds to to a 3 specific gravity of 0.0317lb/in and, therefore, to a pressure gradient of 0.38 psi/ft. Final Conditions

Final conditions are cement displacement with a specific gravity of 15lb/gal, obtained by pressurising the tubing at 5,000psi and the casing at 1,000psi. This operation causes the string to cool to 160°F 160°F at the bottom hole and creates the t he pressure and temperature trend 3 shown in figure 7.cc (15lb/gal corresponds to a specific gravity of 0.0649lb/in and to a pressure gradient of 0.7795psi/ft).

X

X

Y

Y

Figure 7.BB - Example Completion Completion #2

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P (psi)

O

O

0

T (°F)

60

GEOTERMICO

C SG SG e T BG BG

10000

10000

3800

D (feet )

200

D (f eet)

FINAL CONDITIONS CONDITIONS O

1000

P (psi)

5000

O

T (°F)

60

TBG SQUEEZE

CSG

10000

4800

10000

12795

160

D (feet)

D (feet)

Figure 7.CC - Initial and Final Condition (Example #2) Calculation Method a)

Calculation of variations variations in length

The variation in the piston force between initial and final conditions is expressed by:

∆F a = ∆Pi

 A p −  Ai

− ∆Po

 A p

− Ao

= 8995 (8.3 − 4.68) − 1000 (8.3 − 6.49) = 30751.9 lb

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so the variation in length according to Hooke’s Law (piston force) is given by:

=−

 L1

F a L  E  As

=−

30751.9 x 120000 30000000 x 1.81

= − 67.96 in The fictitious force, which is initially zero because P i = Po, is given by: F  f 

=  A p (Pi − Po ) = 8.3 x (12795 − 4800 ) = 66358.5 lb

As this value is positive, then the string is buckled, so it is necessary to determine the position of the neutral point in order to calculate the ∆L2. The weight of string, w, fully immersed in fluids, is calculated in the following way: w fi

= Ai γ  fi = 4.68 x 0.0649 = 0.3037 lb/in

w fo

= Ao γ  fo = 6.49 x 0.0317 = 0.2057 lb/in

w = ws

+ w fi − w fo = 0.542 + 0.3037 − 0.20567 = 0.640 lb/in

The neutral point from the bottom hole is therefore: n=

F f  w

66358.5 0.640 = 103685.16 in

=

As this distance is less than the length of the string, not all the string is buckled. The variation in length ∆L2, is calculated using the first of the two formulae in section 7.4.2.

F2 r 2 ∆L 2 =− 8Elw

−(1.61×66358.5)2 =− 8×30000000×1.6×10.64 =−46.16

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As regards the variation in length due to ballooning, the average variations in pressure along the string can be calculated using the formulae in section 7.4.3:

∆Pim =

(5000 − 0) + (12795 − 3800 ) 2

= 6997.5 psi ∆Pom =

(1000 − 0) + (4800 − 3800) 2

= 1000 psi Therefore, the variation in length caused by ballooning is as follows:

∆ L3 = −

=−

2 ν   E 

∆Pim − R2 x ∆Pom x x  L 2  R −1

2 x 0.3 30000000

2

x

6997.5 − (1.178) x 1000

(1.178) − 1 2

x 120000

= − 34.73 in. As regards the variation in length due to temperature, the formula in section 7.4.4, is used to calculate the average variation in temperature along the string:

∆T M  =

(60 − 60 ) + (160 − 200) 2

= − 20 °F The variation in length is therefore:

∆ L4 = α  ∆T  M   L = 6.9 x 10 − 6 x (− 20) x 120000 = − 16.56 in. The variation in total length of the tubing, if the tubing can freely move in the packer-bore, is therefore given by

∆ Ltot  = ∆ L1 + ∆ L2 + ∆ L3 + ∆L4 1 = − 165.4

in.

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Tubing Permitting Limited Limited Motion

The variation in length calculated above, may sometimes be unacceptable, as it would create seal assembly lengths which are not practicable for the planned type of completion. One method for containing these elongations is to use a tubing permitting limited motion, as it off-loads weight on the packer after it is set (slack-off) and compresses the string. The slack-off operation modifies the variations in length the string will undergo during the subsequent cement squeeze stage as shown below. During initial conditions, oil is the fluid inside the tubing and so: w fi

= Ai γ  fi

= 4.68 x 0.0317 = 0.1483 lbs/in w = ws + w fi − w fo = 0.542 + 0.1483 − 0.20575 = 0.48 lbs/in. Assuming that the slack-off force off loaded on the packer is 20,000lb, the neutral point is located as: n=

F so w

20000 0.485 = 41266.4 in.

=

from the bottom of the string. As this value is less than the total length of the string, it makes it possible to use the formula in section 7.6 in order to obtain:

∆ Lso = − =−

F so  L  E  As

2

−

2

F so r 

8  E  I  w

20000 x 120000

−

(1.61 x 20000)2

30000000 x 1.81 8 x 30000000 x 1.61 x 0.485

= − 49.73 in. The variation in the length of the string during the cement squeeze job, when there is a tubing permitting limited motion is given by:

∆ Lsotot  = ∆ Ltot  − ∆Lso = − 165.41 − (− 49.73) = − 115.68 in. As can be seen, this value is lower than that calculated for a free tubing.

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Anchored tubing

If we assume a condition obtained with a tubing which only permits limited motion, giving ∆Ltotso = -115.68 in. This value may still be unacceptable so it is necessary to use anchoring in both directions. In this case as slack-off after setting the packer is present it is necessary to determine the force required to position the end of the tubing in the packer (F p), thus so setting the elongation ∆Lp =-∆Ltot =115.68 in . Figure 8.6 shows the diagram obtained using the formulae which supplies the force/elongation characteristic for tension and compression. When the data of the example are replaced, the formulae below are obtained (the diagram can be quickly plotted by entering any F values and calculating the corresponding ∆L):

∆ L = − ∆ L = −

F 

452.5 F 

452.5

−

F 2

95403727

[in]

for F<0

[in]

f or F >0 .

If the diagram is plotted with the value of the fictitious force calculated previously (66358.5lbs), it is possible to identify the point where the origin of the axes has moved to. From this point, movement in the direction of elongation by a ∆Lp value is made in order to locate the point which is distant from the curve by a F p value. As figure 7.cc shows, Fp = 37000lbs, so the string is subject to stress at its lower end which is equal to 37,000lbs and the packer is forced upwards by the same amount. d)

Tubing Stress Control

If we consider a tubing anchored to the packer during a cement squeeze operation, with a slack-off of 20,000lbs, the fictitious and piston forces, calculated according to section 7.6, are: F a*

= F a + F  p = Pi ( A p −  Ai ) − P0 ( A p −  Ao ) + F  p = 629 in.

F  f *

= F  f  + F p = 29358 lb

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In the section above the packer (figure 7.bb), the forces at the well head are: *

F a tp

= F a* − ws

xL

= 629 − 6.5 x 10000 = − 64371 in. *

F  f  tp

= F f * − w x L = 29358 − 0.64 x 120000 = − 47442 in.

   i    t   n   e    ]   m   n   a   i   g   [   n   u    l    l   a

   i    t   n   e    ]   m   n   a   i   g   [   n   u    l    l   a

100

50

20 trazione [lbx1000]

-40

40

60

80

100 compressione [lbx1000]

-20

-50

Fp -100

∆Lp

-150

Ff

-200

20

40 compressione [lbx1000]

   i    t   n   e   m    ]   a   i   n    i   c   [   r   o   c   c   a

Figure 7.DD - Anchored Tubing (Example #2)

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Bottom Hole

The piston force generates an axial stress equal to: *

σ a

=

F a

 As

629 1.81 = 347 psi

=

the deformation due to buckling generates an axial stress equal to:

σ b

=

 D r 

=

2.875 x 1.61 x 29358

4  I 

*

F f 

4 x 1.61

= 21095 psi If we replace the σa e σb, values, along with P i = 12795 psi e P o = 4800 psi, the values below are obtained using the formulae in section 7.10:

σo = 51688psi σi = 60223psi , therefore, if we consider the highest value found as equivalent force, the result is we can obtain the following bottom hole safety factor: SF  =

σeq = σi,

σ sn σ eq

80000 60223 = 1.33

=

Well Head *

As Ff tp < 0 the string at the well head is not buckled, stress is generated on the inner wall of the tubing: *

σ a

= =

F a tp  As

− 64371

1.81 = − 35564 psi

σb

= 0 and the greatest amount of

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If we replace the σa value obtained and as p i = 5,000psi and p o = 1,000psi, the value below is obtained using the formula in section 7.10:

σi = 36117 psi therefore as σeq = σi, , the well head safety factor is: SF  =

σ sn σ eq

80000 36117 = 2.21

=

The safety factor for the cement squeeze operation results as the lowest of obtained values, therefore:

SF = 1.33 This value is acceptable because the lower limit for a carbon steel string is 1.25. 7.10.6. Example Computation Computation

As an example we have included two cases of string calculations, carried out using the Wellcat programme supplied by Enertech. The first example is the same as that dealt with by Lubinsky. The second is a case history, analysed during completion studies for the Villafortuna-Trecate field. Particular attention should be paid to data entry and presentation of results in order to obtain knowledge of how the programme handles these two cases. For a description of the programme’s general functions, please refer to the notes in Appendix D and the user’s manual available in the Company’s library. Examples done with the Vertubing programme, have been deliberately omitted as this programme is no longer used by Eni-Agip Division and Affiliates. Therefore only a brief description has been given in Appendix D. For further information please refer to the user’s manual.

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8.

SUB-SURFACE EQUIPMENT

8.1.

PACKERS

0

The types of packer systems and applications have already been described in section 5.3.1. This section defines the series of criteria for choosing packer characteristics to apply to single and selective completions. The packers considered are listed in table 8.a below. The proposed criteria for the choice only take into consideration general technical aspects and do not cover the individual characteristics of particular models or tools, while still reflecting the needs which lead to selection of the most commonly used models. Once the packer type and model have been defined, the next stage is establish its performance to meet with all the expected operating conditions (applied force and pressure differences). For this reason regarding permanent packers, reference is made to the operating ‘Envelopes’; i.e. operating diagrams for the packers supplied by the manufacturer of the particular packer and to the pressure ratings for retrievable packers.

Type Of Packer

Setting Method

Permanent

Mechanical

Permanent/  Retrievable Retrievable

Setting Tool

• •

Hydraulic setting tool Electric line

Sealbore Features

• •

Std/Large/Dual Std/Large/Dual

Hydraulic

N/A

Std/Dual

Mechanical

N/A

Std/Large/Dual

Hydraulic

N/A

Std/Dual

Hydraulic

N/A

Hydrostatic

N/A

W eight

N/A Table 8.A - Packer Types

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Selection Procedure

Packer selection has three stages: 1) 2) 3)

Selection of type of packer Selection of setting mechanism Selection of main packer accessories including the tubing-packer connection

In stage 3, stress analysis is carried out to check the completion string (packer and tubing) under the stress to which they are exposed, refer to section 7.5 which describes the iterative process of tubing weight/grade/stress calculations. 8.1.2.

Selection Criteria

Various representations can be used to describe the categories of criteria. This section illustrates the flow diagrams, identifying the standard procedures for each stage (Refer to figure 8.a.). The selection process includes the following categories of data: General Well Data

This includes data which effects the configuration of the well to be completed, the most important being:

• • • • •

Location (on-shore/ off-shore platforms, off-shore under water) Pressures and temperatures Type of well (production, injection) Type of fluid produced (oil, gas) Deviation (max. deviation angle).

Completion Data

This includes the following parameters such as:

• • •

Type and density of the completion fluid Perforation of the casing using tubing-conveyed or wireline techniques Use of a production liner.

These data also include type of packer chosen and setting, setting depth, etc. Operational Data

The following operational data are required:

• •

Stimulations (planned, unplanned) Type of de-compression operations, in particular: a) removal of the tubing by itself b)

• •

removal of the tubing and packer simultaneously

Planned frequency of de-compression operations Potential damage to the formation caused by the workover fluid.

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Figure 8.A - Selection Process Diagram

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Well Classification Classification

An important parameter for defining the characteristics of a packer is the ‘degree of difficulty of the well to be completed’. To this end four classes of well have been identified which are used to analyse the various problems involved in the selection of the packer: 1)

High corrosive wells

• 2)

Highly critical wells:

• • • • • • 3)

Deep depths > 4500m. High temperatu temp eratures, res, SBHT > 130° 1 30°C. C. High pressures, SBHP > 700 atm. Subsea well-head well. Platform well having the risk of failure due to the potential collision from a vessel with the structure. Gas injection well with pressures, ITHP above 3,000psi.

Critical Well

• • 4)

The fluids have high corrosive problems.

Temperatures Tempera tures between bet ween 100 and 130° 130 °C Depths between 3,000 and 4,500m.

Non-critical well

• •

Depth of less than 3,000m. Temperatures Tempera tures below b elow 100 °C. °C.

The depths indicated are true vertical depths. 8.1.4.

Packer Selection For Single String Completion Completion Type Of Packer Procedure

The choice is mainly linked to the type of well: 1) 2) 3)

In the case of a highly critical well, select a permanent packer. If the well has high corrosive, select a permanent/retrievable or permanent packer, with priority be given to the former. If the well is critical or non-critical, (Refer to figure 8.b).

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Figure 8.B - Type of Packer P acker for Critical and Non-Critical Wells

Explanation of figure 8.b: (A) High High frequenc frequency y of tubing tubing pullou pullout. t. (B) High frequency of tubing-packer pullout. (C) Use of TCP TCP drilling drilling techniques. (D) Measured well depth

≥ 3000 m.

(E) The workover fluid damages the formation. (F) The packer fluid is a high density mud (> 1.6 kg/l) with probable solid deposits on the packer. (G) Gas injection well with with injection pressure > 3,000psi.

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At points A and B, high frequency of extraction corresponds to a completion life of less than five years. The rectangle ‘Choose’ indicates the choice between the two alternatives, the priority is indicated by a number (‘1’ corresponds to a higher priority than ‘2’). For example, in the choice is made on the basis of point (D) then there are no particular constraints (no workovers, or requests due to the completion fluid characteristics). The safety factor of using a retrievable packer or not depends on the criticality of the well and, in particular, on its depth. Packer Setting Method

Permanent and Permanent/Retrievable Packers The selection is dependent mainly on the well characteristics: 1) 2) 3)

If the well is corrosive or very critical, choose hydraulic setting. If the well is critical or not critical, (Refer to figure 8.c). Reference (A) is only true if one of the following conditions are relevant:

• • • •

SBHT SBH T > 150 1 50 °C °C (= 270 °F). Is a deviated deviat ed well, with a maximum ma ximum deviation devia tion angle ang le > 50°. The completion fluid = mud with density > 1.6 kg/l. Gas a production product ion liner with inclination inclin ation > 30°. 30°.

Figure 8.C - Packer Setting Method for Critical and Non-Critical Non-Critical Wells

For a mechanical type permanent packer, the setting is defined by the conditions detailed in (A). The same procedure will also be used later for packers of the type used in a selective type completion.

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Retrievable Packer Setting Method

The method of setting used for retrievable packers is made, following the diagram in figure 8.d:

Figure 8.D- Retrievable Packer Setting Method

1)

Check (A) is only true if one of the following conditions are relevant:

• • • • 2)

Check (B):

• 3)

There is high frequency of tubing pullout (life of the completion < 5 years).

Check (E):

• 5)

Using TCP shooting techniques.

Check (C):

• 4)

The well is deviated deviat ed with a maximum deviation angle of o f > 20°. The bottom-hole bott om-hole temperature (SBHT) is > 60 °C. °C. The vertical depth of the packer setting is > 2,000m (this is true to definitive and not test completions). Stimulations are planned.

Completion fluid and damage to the formation

Check (F):

•

The packer fluid is a high density mud (> 1.6 kg/l) with the probability that it leaves solid deposits on the packer.

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The decision of whether to use a hydraulic, or hydrostatic, set is left to the engineer. The main consideration is the required setting pressure (lower for hydrostatic packers) which influences the wellhead pressure rating. The conditions at the moment of packer setting decides whether to use a retrievable packer. If these are outwith the capacity of the retrievable packer, a permanent/retrievable packer will be utilised and consequently, the corresponding setting procedure will have to be adopted (see permanent packers above). Permanent And Permanent/Retrievable Permanent/Retrievable Packers Pack ers Setting Method

There are principally two aspects to analyse:

• •

The choice of the tubing-packer connection. To integrate this choice with the stress analysis procedures.

If during the application of the stress analyses of the string gives negative results, a configuration which fulfils the stress analysis requirements must be considered for the packer-tubing connection 5. The shear ring value is generally set by increasing the maximum force applied to the packer by 25%. The maximum force is determined using stress analysis (to take into account the tolerance of the nominal shear value ± 5 to 10%). The shear value is checked for the stress conditions at the wellhead section during the packer release stage. Tubing-packer connections seal assembly elements will be of the moulded seal type when subjected to alternating pressure cycles, e.g. gas injection wells where the IBHP is greater than the packer fluid pressure and SBHP is lower than the packer fluid pressure. Highly Critical Well: Anchored Completion

For a highly critical well, the approach is the same as that for an anchored tubing-packer. defines the type of anchoring on the basis of the conditions for (A), in particular the choice is made between a shear release or anchor seal assembly. The type of anchor to be used can be defined during this first stage for an anchored completion (without shear release):

•

If the packer is set mechanically, the anchor will be a ratchet type or, alternatively, fixed.

If the stress analysis results are negative:

• •

If a shear release is needed, an anchor seal assembly is used. If anchor is needed, a dynamic seal is used (Refer to figure 8.d).

5 If the failure of the stress analysis is due to the tension caused by the tubing-packer connection. At present the stress analysis procedure is developed using the “Veritas “ software package .Veritas is the UNIX version of the VERTBG package.

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Figure 8.E - Anchored Completion Completion Option

Check (A): Deviated well:

•

if it is an injection well it cannot be critical (see section 8.1.3).

For an anchor with shear release:

•

If the stress analysis upon releasing is negative, an anchor will be used and the check will be carried out again.

Highly Critical Well: Dynamic Seal

This stage considers an anchored completion which fails the stress analysis calculation because of problems associated with the tubing-packer connection. In this case a dynamic seal is used (Refer to figure 8.f).

Figure 8.F - Dynamic Seal

Check (A)

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The packer fluid is a high density mud (> 1.6 kg/l) which may leave solid deposits on the packer.

Check (B):

•

The packer is one trip installation, i.e. run on the tubing. This is only possible with hydraulically packers.

The procedure illustrated in figure 8.f gives a general description of the criteria behind the choice of dynamic seal to be adopted. Reference will be made to this later and also for cases which are different to those described in highly critical wells above. Here, following any failure of the stress analysis, no other rules are apply as, in general, when using dynamic seals, the stress analysis results are corrected using factors other than the seal element. Critical, Non-Critical Well

The easiest solution in these cases is to choose a Standard Seal Locator. This is the case with the following conditions:

• • •

No stimulations are planned. The well is not an injection well. The packer is not set hydraulically.

If these conditions do not apply, the procedure illustrated in figure 8.g is followed.

Figure 8.G - Critical and Non-Critical Non-Critical Wells, Seal Element

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Check (A):

•

the packer fluid is a high density mud (> 1.6 kg/l) which may leave solid deposits on the packer.

•

deviated well with max. deviation angle > 20.

•

expected life of the completion < 5 years.

•

the packer is set mechanically.

(B):

(C):

(D):

Again in figure 8.g, the outlet conditions included in the rectangle indicate, besides the choice of tubing-packer connection, the need to use the packing setting procedure specified. In the case of a deviated well, anchored completion is not recommended. It is better to use a completion with a shear element which is more easily releasable, or a dynamic seal whenever feasible. No additional adaptation of the seal element is foreseen as a consequence of any stress analysis. Retrievable Packer Tubing-Packer Connections

The choice of the tubing-packer connection for retrievable packers (hydraulic and set down weight) is made on the basis of that in figure 8.h. Particular conditions raise questions over which type of retrievable packer to use. In these cases, a permanent/retrievable packer is the priority or a permanent should be used and consequently the associated setting procedure and seal assembly selected.

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Figure 8.H - Tubing-Packer Connections for Retrievable Packers 8.1.5.

Single Selective Completion Completion Packers

The criteria illustrated here are valid for selective completions with 2 or 3 producing zones. The solutions given are for a case with only 2 zones and if a third zone is to be taken into consideration it is assumed that the selection made for the upper zone of the two zone scenario applies. Packer Selection

The first case classifies the well on the basis of depth characteristics ( ≥ 4,000m) but more on the basis of its complexity.

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Figure 8.I - Single Selective Packer For Complex Wells

if several different configurations are available, as for example in figure 8.i, the engineer has a certain degree of freedom of choice but is, however, governed by the order of priority specified along with the choices. If the conditions as of figure 8.i, are not applicable, these cases are classified by well depth:

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Figure 8.J - Selective Single Well with Depths Between 3,000 and 4,000m

Figure 8.K - Selective Single Well with Depths Between 1,500 and 3,000m

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Figure 8.L - Selective Single Well with Depths Less Than 1,500m

In the case of depths less than 1,500m in a well not considered complex, it is strongly recommend that a retrievable type packer be used. Application of the criteria illustrated in figure 8.i through figure 8.l is common with the only exception, in the case of multiple choices, being that the order of priority for the lower zone can be changed by applying the following rules:

• •

If workovers are planned with removal of the tubing and packer, and a retrievable packer is one in the list of possible choices, then it should be selected. If the completion fluid is a mud with deposition problems, and a permanent or permanent/retrievable packer are in the list of possible choices, then the permanent/retrievable should be selected over of the retrievable.

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Packer Setting Method

The type of setting method proposed depends on the following factors:

• •

Type of packer Setting distance between the packers.

The setting criteria of a mechanical permanent packer (on a workstring, or wireline) are those already defined for the single completion described in section 8.1.4. Permanent Stacked Packers:

Refer to figure 8.i with all permanent packers, if the setting distance between the packers is > 500m (check with the packer manufacturer), choose hydraulic setting for all the packers or else mechanical setting. Lower Permanent Packer With Upper Retrievable:

Refer to figure 8.j, figure 8.k and figure 8.l, in these cases the reference packer is permanent and the other packers are the retrievable or permanent/retrievable type. With these type of packers, if the completion fluid is a brine, hydraulic type setting should be used or else the packers can be set mechanically. Mechanical setting is preferred for the reference packer and the setting should be by electric line when the distance between the packers is < 500 m. If the reference packer is set by a workstring, a depth control procedure is necessary to verify the depth of the packer setting to ensure positioning of the blast joint across the upper zone which is open to production. All packers are Retrievable

Refer to figure 8.k and figure 8.l where all packers are retrievable, hydraulic setting should be used for this type of packer. It is essential to check with manufacturers that the distance between the packers is sufficient for the packers to be set. Tubing-Packer Connection Selection

The criteria continues by classifying the packers by type and setting with the zones treated separately. In some cases, three zones are assumed (upper, intermediate, lower). In cases where there is no specific mention of an Intermediate zone, it is treated with the same criteria used for the upper zone. Generally, the results of the stress analysis specifically identifies the packers with releasing problems. Due to this, the zones are be treated separately; i.e. modifications are be made only to those packers which have the problems. It is recommended in any case to re-check the completion after having made the modifications.

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Upper packer

The rules described for the single completion are applied to the upper packer (Refer to 8.1.4). Lower or Intermediate Packer

There are three possible ways of treating the lower zones: 1)

2)

3)

All the packers are of the permanent or permanent/retrievable types with hydraulic setting. Initially an anchor with shear release should be selected. In the case of failure of the stress analysis on this packer, a dynamic seal will be used (anchor with PBR or telescopic joint). The lower zone packer is a permanent with mechanical setting. A dynamic seal should be used; in particular, a standard length locator. In the case of failure of the stress analysis, a longer locator with seal bore extension should be used. For the intermediate zone in the three zone case, an anchor or retrievable type packer will be used, for the intermediate packer. The lower zone packer is a retrievable. In the case of failure in the stress analysis a dynamic seal with telescopic joint will be used. used .

For the intermediate zone in the case of three zones, a telescopic joint should be used when there is failure in the stress analysis.

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SUB-SURFACE SAFETY VALVES

This section provides the Eni-Agip Division and Affiliates policy and guidelines for the application and selection of Sub-Surface Safety Valves (SSSV). The policy defined shall be applied to all Eni-Agip Division and Affiliates completion designs world-wide. Any variation to this policy and selection procedures herein, shall only be sanctioned by the Eni-Agip Division and Affiliates Head Office. 8.2.1.

Policy All Eni-Agip Division and Affiliates completions shall incorporate a SSSV in the completion string string to provide safety in the event of an uncontrolled well flow.

Surface controlled sub-surface safety valves (SCSSV’s) shall be used accordingly to the criteria listed below in section 8.2.4. 8.2.2.

Applications

The applications for SSSV’s are given in section 8.2.5. The choice of SSSV for a particular development will depend on:

• • • •

Well location Fluid properties Required flow area Well intervention capabilities.

This will determine whether the selected SSSV is Wireline Retrievable (WRSV) or Tubing Retrievable (TRSV). 8.2.3.

Wireline Retrievable Safety Valves

Wireline retrievable valves may be, either, sub-surface controlled sub-surface safety valves (SSCSSV) otherwise known as direct acting valves or surface controlled sub-surface safety valves (SCSSV). SSCSSV’s are either pressure differential or ambient pressure operated valves. Both types are generally referred to as ‘storm chokes’. The use of these valves should be avoided as they are set up to operate on predetermined conditions representing a major leak at surface, e.g. a flowline rupture, but under some circumstances, when there is a leak of insufficient rate, the valve may fail to close. In conjunction, flow erosion of the valve internals may alter the closure settings. A derivative of the storm choke is the injection valve which is held open by water or gas injection and closes when injection ceases.

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Surface Controlled Sub-Surface Safety Valves

These are designed for tubing retrievable, wireline retrievable or annulus safety valve systems. They are controlled normally by surface applied hydraulic pressure through a control line clamped to the outside of the tubing string. Hydraulic pressure opens and then retains the valve open. Removal of the pressure allows the valves to close. These valve systems are fail safe and are preferred to SSCSSV’s. The guidelines given in section 8.2.5 indicate in which applications WRSV’s and TRSV’s should be used. The following table 8.b specifies when SCSSV’s shall be used.

Well Type

Criteria

Oil Producer

Gas producer Gas storage Gas injection Water injection Artificial lift

H2S in produced fluids

• • • • • • • • • • • •

All new offshore development. All wells onshore which can sustain natural flow. All old wells in above categories which are to be recompleted. All isolated wells. All new offshore development. All old wells being recompleted. All wells. All wells. All wells. All wells on gas lift, tubing and annulus. Electrical submersible pump, tubing and only annulus if used for gas venting. All wells.

Table 8.B - Criteria For Use of SCSSV's 8.2.5.

Valve Type/Closure Mechanism Selection

This section gives recommendations on the choice of valve with the corresponding type of closure mechanism. Note: ote:

All valv alves with with ball ball type type clos closur ure e mec mecha hani nis sms are are not not reco recom mmende ended d for for use as they are less reliable than flapper valves.

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Applications

• • • • • •

Offshore platform wells. Subsea wells. Wells with the presence of H2S or CO2. Wells with surface flowing temperature greater than th an 130° 13 0°C. C. Wells with shut-in surface. As on insert valve for tubing retrievable SCSSV’s.

Storm Chokes

•

As a backup to the WRSV above when there is a control line failure. Set in the next lowest lowest wireline nipple.

Annular Safety Systems

• • • •

Gas lift wells. ESP wells with gas venting. Jet pump wells, under the pump.

Wireline Retrievable Injection Valves

All waste wells.

Table 8.C 8. C - SSSV S SSV Closure Mechanism Applications Applications

Gas or water injection wells may have either a tubing retrievable or wireline retrievable SCSSV. 8.3.

CONTROL/INJECTION CONTROL/INJECTION LINE SELECTION

The purpose of this sub-section is to define the basic criteria for the selection and the use of small diameter tubes for SCSSV control line and injection line applications. These two different cases will be considered separately below. 8.3.1.

Control Lines

Tube used as ‘control line’ to operate downhole safety valves are installed along with the production string. In this case, SCSSV’s are usually set at shallow depths and, therefore, the length of line required is generally relatively short. 8.3.2.

Injection Lines

Tube used as ‘injection lines’ to inject chemical products such as corrosion or scale inhibitors down hole or as deep as possible in the well, are also installed with the tubing string. The line length required in this case, will be considerably longer.

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Tube Specifications Size

Small diameter tubes for control or injection line applications are manufactured either as seamless or seam-welded and sunk. They are usually available in a full range of materials and sizes. In the seamless tube manufacturing process, the raw material comes in the form of extruded hollows, which are then reduced to the desired diameter and wall thickness by a cold drawing operation. In the case of welded tube process, the raw material comes in strips which are first rolled into tube form which is fed through a welding head to perform a fusion weld. The cycles of cold drawing with a floating plug drawing method is preferred and annealing operations performed to reach the desired dimensions and produce a weld zone homogeneous with the rest of the tube material. Welded tubes are considered the norm as opposed to seamless which are considerably more expensive and limited in length (usually a max. of 1000 ft in length). Welded tubes can be produced in extra long coils more than 3200 ft by butt welding lengths of tubings together. Both types of lines comply with ASTM specification A269 ‘Seamless and Welded Austenitic Stainless Steel Tubing for General Service’ and ASTM-B751 specification ‘General requirement for Ni and Ni alloy Seamless and Welded Tube’. 1

The standard size for both applications, control and injection line, is  / 4” OD and the wall thickness chosen from among the following sizes according to the pressure requirements:

• • •

1

 / 4” OD x 0,035” wall thickness  / 4” OD x 0,049” wall thickness 1  / 4” OD x 0,065” wall thickness. 1

Control Line Working Pressures P ressures

A down hole safety valve is usually set at a relatively shallow depth, ranging about 30m to 50m from well head for on-shore installations or from sub sea level in case of off-shore activity. For this reason the configuration of the control line is not effected by the well deviation, therefore in most cases external encapsulation it is not recommended. Once the working pressure has been defined as explained in the following paragraph, refer to table 8.d for the selection of the size which most suits the requirements. The working pressure (WP) is defined as follows: WP = Safety Valve WP + Valve Opening Pressure

Safety Valve WP is as specified by the manufacturer. Valve Opening Pressure, provided by the manufacturer, is the pressure required to overcome the closing force of the spring plus resistance due to friction effects. Usually it ranges between 1,500 to 2,000psi depending on the manufacturer.

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Chemical Injection Line Working Pressures

Chemical injection lines are run to injection mandrels which are installed as close as possible to the bottom of the tubing. The definition of working pressure is based on the following considerations:

• • • •

Well configuration, therefore total vertical depth. Injection fluid characteristics such as density and viscosity. Injection rates to choose the correct diameter and evaluate friction losses. Total pressure required to inject chemicals through the line.

Injection rates referred to in this application are always low, therefore the flow profile can be assumed to be laminar. Once the friction losses for laminar flow have been calculated then the diameter size can be determined accordingly. figure 8.n shows the graphs of pressure losses per 100m versus flow rate plotted for various internal diameters and various values of fluid viscosity. Once the working pressure has been defined as explained below, (Refer to table 8.d), the selection of the tubing size to meet with requirements can be made. Working pressure is defined as follows: WP

= BHSP + P fr − Phd  Eq. 8.A

where: WP  = BHSP = P fr  = fr  P hd  = hd 

BHSP + Pfr - Phd  Bottom hole static pressure. Friction lo losses (s (see fifigure 8. 8.n). Hydro drostati tatic c pre pressure of injecti ectio on flu fluid.

The pressures given in the table are computed with ultimate and yield tensile strength values given in table 8.f and they are rated rate d to temperatures between -20 and 100° 1 00°F. Values obtained are based on the Lamè’s formula for thick section pipes using internal pressure only and stress defined at the internal diameter face, combining radial and tangential stress to determine an equivalent resultant using the Von Mises Theory of Distortion Energy:

P

=

 OD 2  Ys    − 1  ID       4

 OD   + 1 3x    ID

Eq. 8.B

Variables are defined as: P Ys Ys WP OD ID

= = = = = =

computed pressure (psi) ulti ultim mate ten tensile stre trength ngth to compute ‘Burs urst Pressure’ (psi) yield eld strength (2% offs ffset) to compute ‘Test est Pressure’ (psi) 80% of test pressure (psi) outside diameter (in) inside diameter (in)

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Type of alloy

OD (inch)

Wall (inch)

WP (psi)

Burst (psi)

Test (psi)

AISI 316 L

0 . 250

0 . 035

5 . 328

1 8 . 646

6 . 65 9

0 . 250

0 . 049

7 . 118

2 4 . 914

8 . 89 8

0 . 250

0 . 065

8 . 809

3 0 . 831

1 1 . 011

0 . 375

0 . 035

3 . 651

1 2 . 780

4 . 56 4

0 . 375

0 . 049

5 . 004

1 7 . 515

6 . 25 5

0 . 250

0 . 035

5 . 967

1 8 . 646

7 . 45 9

0 . 250

0 . 049

7 . 972

2 4 . 914

9 . 96 5

0 . 250

0 . 065

9 . 866

3 0 . 831

1 2 . 333

0 . 375

0 . 035

4 . 089

1 2 . 780

5 . 11 2

0 . 375

0 . 049

5 . 605

1 7 . 515

7 . 00 6

0 . 250

0 . 035

7 . 459

2 2 . 642

9 . 32 3

0 . 250

0 . 049

9 . 965

3 0 . 252

1 2 . 457

0 . 250

0 . 065

12 . 333

37 . 4 3 8

15 . 416

0 . 375

0 . 035

5 . 112

1 5 . 518

6 . 39 0

0 . 375

0 . 049

7 . 006

2 1 . 268

8 . 75 7

0 . 250

0 . 035

12 . 786

31 . 9 6 5

15 . 983

0 . 250

0 . 049

17 . 084

42 . 7 0 9

21 . 355

0 . 250

0 . 065

21 . 142

52 . 8 5 4

26 . 427

0 . 375

0 . 035

8 . 763

2 1 . 908

1 0 . 954

0 . 375

0 . 049

12 . 010

30 . 0 2 5

15 . 013

Monel K400

Incoloy 825

Inconel 625

Table 8.D - Theoretical Working, Bursting and Testing Procedures (for welded weld ed stainless stain less steel ste el tubing at a t between betwe en -20°F -20°F to 100°F) 100°F) 8.3.4.

Material Selection

Among the stainless steels and nickel alloys available, the most commonly used for control or injection line applications are listed in table 8.e together with their relative characteristics. Compatibility of packer or completion fluid with the selected material must be confirmed by means of condition specific laboratory testing. table 8.f shows the mechanical properties of these materials in the annealed condition.

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Type of Alloy

Main Characteristics

AISI 316 L

Is an austenitic stainless steel with reduced carbon content. Has good resistance to grain boundary attack and improved resistance to pitting and crevice attack. It is susceptible to chloride stress cracking when the presence of stress is combined with a packer fluid containing chlorides.

Monel K400

Is a nickel-copper alloy resistant to corrosion and stress corrosion over a wide range of conditions.

Incoloy 825

Is an austenitic nickel-base alloy with good resistance to pitting in chloride solutions and to stress corrosion has improved resistance to corrosion by many acids.

Inconel 625

Is a Nickel-base alloy with a higher percentage of molybdenum to give the highest resistance to chloride attack.

Table 8.E - Stainless Steels and Nickel Alloys Most Commonly Used

Once the type of material to be used has been defined, based on pressure ratings and working environment, the corrosion department should be consulted to confirm compatibility with the packer fluids. Control or Injection line made of the above material shall comply with the following ASTM specifications: AISI 31 316L Monel nel K40 K400 0 Incoloy 825 Inconel 625 625

-

In ac accordance wi with AS ASTM specific fication A2 A269 (T (TP316L). In ac accord ordanc ance wi with AST ASTM spec pecific ficati ation B1 B165. In acc accord ordanc ance with AST ASTM spec pecific ficati ation B42 B423. In acc accord ordance nce with AST ASTM spec pecific ficati ation B704 704.

Type of Alloy

Tensile Strength (psi)

Yield Strength at 0.2% Offset (psi)

AISI 316 L

70 , 000

25 , 00 0

Monel K400

70 , 000

28 , 00 0

Incoloy 825

85 , 000

35 , 00 0

Inconel 625

1 2 0 ,0 0 0

60 , 000

Table 8.F - Nominal Mechanical Properties in Annealed Conditions (For temperatures tempera tures between bet ween -20 to 100°F) 100°F)

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Fittings

Connections for either SCSSV control lines or chemical injection lines shall be performed as follows:

•

In case of pressure rating < 5000 psi, line connections shall be of the ‘Swagelok’ type. • In case of pressure rating > 5000 psi, line connections shall be of the ‘Autoclave’ type as recommended by API Spec. 6A (Wellhead & Christmas Tree Equipment) at the paragraph ‘Equipment specification requirement’ under ‘test and gauge connections’. It is suggested to avoid, as far as possible, any intermediate connections to reduce potential leak paths. 8.3.6.

Protectors

Control line protectors are designed to support and avoid (bare or encapsulated) crushing at where it is most exposed, e.g. where it crosses large offsets like couplings, downhole safety valves or gas lift mandrels. Protectors shall be designed for small annular clearances allowing sufficient annulus flow area. They should be of the “one piece” type without loose parts and designed so as to be quickly installed and removed. ‘Across coupling tubing protectors’ are recommended for use with both SCSSV control and injection lines applications. For control lines used on SCSSV’s installed at shallow depth (less than 250m), other types of protectors may be used. In general, ‘steel banding’ or ‘banding straps’, ‘rubber based’ and ‘mid joint protectors’ shall be avoided at all costs. The following technical requirements will identify protector performance:

• • • • •

Material shall be of all metal construction. No structural welding shall be allowed. Lab corrosion tests shall be run to verify compatibility with annular environment. Capable of firmly supporting bare or encapsulated lines when performing completions and recovery during workover allowing control line and protector reuse. Force indicated in ‘l’ or ‘tons’ that the protector will support against axial displacement without failing or damaging the supported line. Force stated in ‘lb’ or ‘Kg’ that protector will resist as a direct pull on supported line without any slippage. Maximum load expressed in ‘lb’ or ‘kg’ that protector will withstand when contacting the casing wall without damage.

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Encapsulation

Encapsulation of this line is recommended only for chemical injection lines applications. Encapsulation increases crush resistance during installation, protects line against abrasion, pinching and improves clamping profile. Several encapsulation materials are available, covering a wide range of environmental conditions. table 8.g indicates the compatibility of the main encapsulation materials with the most commonly used packer/completion fluids. In some cases, braided wire is placed alongside the injection line and bonded together by the encapsulation material, to further enhance resistance and strength avoiding any rolling and twisting tendencies (Refer to table 8.h). The following laboratory tests are suggested to confirm the lines mechanical characteristics and compatibility of the encapsulation material with the packer fluid used:

• • • • • •

Immersion test of the encapsulated line in downhole conditions for a defined period of time. No evidence of a change in physical appearance should be observable. Gas impregnation tests at various temperatures, pressures and with various gasses for a fixed period of time. No evidence of cracking, blistering or embrittlement should be observable. Combined brine/sour gas exposure tests according to the operating conditions, as above. Combined crude oil/sour gas exposure tests according to operating conditions as above. Abrasion resistance test to compare the resistance against abrasion between bare and encapsulated lines. Crush resistance test by loading the tube laterally, across the diameter, simulating various loading levels, until tube collapse is evident. Encapsulated line results should be compared to bare line tests.

The following table 8.g shows the main properties of the most common types of encapsulation material available. The choice of material, is mainly based on type of packer fluid, well deviation and working temperatures to be experienced and shall be confirmed by laboratory tests for compatibility.

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Encapsulation Material

Main properties

Nylon

Compatible with diesel packer fluids containing high gas percentages. Nylon should not be used with completion fluids that contain calcium chlorides, calcium bromides or zinc bromides at high temperatures. Its maximum temperature rating is 250°F.

Santroprene

Compatible with most packer fluids with the exception of diesel or fluid at high gas concentration. Maximum operating temperature rating is 275°F - 300°F.

Halar

Chemically resistant to almost all downhole fluids. Excellent mechanical strength and abrasion resistance. Compatible with high gas content environments. Recommended for highly deviated wells. Maximum operating operat ing temperature tempe rature is 400° 400 °F.

Rislan II

Chemically resistant to almost all downhole fluids. Excellent mechanical strength and abrasion resistance. Compatible with high gas content environments. Recommended for highly deviated wells. Maximum operating operat ing temperature tempe rature is 212° 212 °F.

Foraflon PVDF

Chemically resistant to almost all downhole fluids. Excellent mechanical strength and abrasion resistance. Compatible with high gas content environments. Recommended for highly deviated wells. Maximum operating operat ing temperature tempe rature is 302° 302 °F.

Table 8.G 8. G - Compatibility Compatibility and Characteristics of Encapsulation Materials

Halar (fluoropolymers) is a registered trademark of Ausimont USA Santoprene (thermoplastics rubber) is a registered trademark of Monsanto Rilsan II (polyamide thermoplastic) Foraflon PVDF (polyvinylidine fluoride thermoplastic t hermoplastic material) Samples of different types of encapsulated tubes have been tested under compressive, laterally applied, loading simulating possible damage arising during installation to determine the tube crushing resistance and extend of polymer damage, (see Table below).

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Sample Size

Applied load in metric tons (no damage detected)

100mm - 1/4” OD x 0.049” Alloy 825 bare line 100mm - 1/4” OD x 0.049” Alloy 625 bare line 100mm - 1/4” OD x 0.049” Alloy 825 encapsulated with Foraflon: size 15mm x 12mm

2 . 45

Applied load in metric tons (line partially crushed, fluid flow not interrupted) 3. 5

2 . 65

3. 8

7. 0

9. 0

Table 8.H - Crush Resistance Resistance Test Te st For Encapsulated Injection Lines 8.3.8.

SCSSV Hydraulic Hydraulic Control fluid

The criteria in this section is for SCSSV control line applications only. Today hydraulic fluids are almost exclusively based on mineral oils. Other types of synthetic based oils, are employed only when operating temperatures are very low and special thermal standby properties are required. Most of the synthetic based oils used are of the flash fire resistant category as they have a very low pour floc point combined with a good performance at higher temperatures. With regard to subsea completions, the control fluid is the same fluid as used for the Xmas tree controls. table 8.i shows the main properties of the recommended oils for control line applications. 8.13 and figure 8.n below shows typical friction losses of control line fluids.

Injected fluid viscosity = 5cP

Fri c. los ses psi  /10 0m

100 90 80 70 60 50 40 30 20 10

O.D = 0,25 inches

w.t.= 0,035 w.t.= 0,049

0 0

1

2

3

4

5

6

7

8

9

10 10

Q injection injection - liters/hr

Figure 8.M - Fluid Friction Loss with 5cP Fluid

w.t.= 0,065

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Injected fluid viscosity = 1cP 20 18 16   m    0    0    1    /    i   s   p   s   e   s   s   o    l  .   c    i   r    F

14 12 10 O.D = 0,25 inches

8 6 4

w.t.=0,035

2

w.t.=0,049

0 0

1

2

3

4

5

6

7

8

9

10 10

w.t.=0,065

Q injection - liters/hr

Figure 8.N - Fluid Friction Loss with 1cP Fluid

The above graphs are based on the following formula: Pf 

=

Q x L xµ 

612.95  Di 4 Eq. 8.C

where:

Friction ion losses losses kPa kPa P = Frict Internal al diamet diameter er (inch (inches) es)  Di = Intern  L

= Len th (meters ters)) = Viscosit sit (cP) = Flow Flow rate rate lt / min min

kPa X 0.145 = psi

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Agip Arnica 32 (Petroleum based)

Agip OSO 32 (Paraffinic based)

Agip Betula S 32 (Synthetic based)

Viscosity at 40° C cSt

32

30

2 9 ,4

Viscosity at 100° C cSt

6 ,4

5 ,3

5 ,1

Viscosity index

1 63

11 0

98

Pour Point °C

- 39

- 30

- 55

Flash point °C

2 02

20 4

2 06

0 , 86 5

0 , 87 5

0 ,8 4 1

-

-

- 60

Density at 15° kg/l Floc point °C

Table 8.I - Properties of Recommended SCSSV Hydraulic Oils

* cSt x Density = cp **Density **Densit y variation variatio n = 0.00065 (kg/l) (kg /l) / °C For standard applications Agip Arnica 32 is recommended as it has better theological properties than OSO 32. Agip Betula 32 should be employed only when operating temperatures are very low as in Siberia where temperatures may reach -50°C. -50°C. In order to avoid plugging of the control line while running in hole, testing and running procedure must be carefully programmed and hydraulic fluid may have to be flushed through a filtration unit, if required (usually 5 micron absolute).

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Control/Injection Line Selection Procedure Flow Chart

Figure 8.O - Control/Injection Line Selection Flow Chart

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WIRELINE WIRELINE NIPPLE SELECTION

The nipples required for completion purposes are based on the results of the previous design stages. The aim of this section is to determine the type (selective or tapered) and configuration of the diameters in order to optimise access to the sump and prevent friction pressure drop. This must take into consideration all the diameter constraints imposed by the casing profile and completion characteristics. The nipples are selected based on those most commonly used by the company; and include the following models: Selective:

•

Halliburton (previously Otis) X, XN, R, RN The choice of the type of nipple is subject to the working pressure which characterises the completion (e.g. SCSSV or wellhead). X and XN nipples are used for working pressure < 10,000 psi, while R and RN types are used on all higher pressures. Tapered:

•

Baker F top no-go (AF-HF-VF) and R bottom no-go (AR-HR-VR). Like the case in selective nipples, the choice depends on the working pressure of the string configuration AF, AR (WP < 10,000 psi) HF, HR (WP between 10,000 and 15,000 psi) VF, VR (WP > 15,000 psi). The principal physical characteristics of a nipple are:

• • •

Seal bore diameter No-go diameter, if applicable Lock mandrel OD (LMOD).

Data on all of these nipples can be found in the manufacturer’s current catalogue. Do not rely on data produced elsewhere or use old catalogues as changes to the nipple systems may have been made resulting in incompatibility.

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Tapered Nipple Configuration

The configuration of the nipples begins at the top of the string and moves downwards towards the bottom or packer tailpipe. The following physical dimensional values are required:

• •

Running clearance (RC) = 0.050ins No-go dimension (NGD) = 0.050ins for tubing OD < 3.313ins = 0.060ins for tubing OD < 5ins = 0.080ins otherwise

The first nipple, generally in the tubing hanger, is always a Baker type F and is chosen with the maximum diameter available for the size of the completion tubing below the hanger. For the lower nipples, the minimum top and bottom restriction dimensions are determined by the following procedure: 1)

The top restriction (RA) is the minimum upper diameter of the nipple, chosen from one of the following:

• • • • • 2)

ID of the packer Drift of the tubing ID of the safety valve Vertical access of the wellhead Sealbore diameter (top) or no-go ID (bottom) of the upper nipple.

The bottom restriction (RB) is determined by the ID of the SCSSV tubing-retrievable, and the only one used. At this stage a hypothesis of seal bore diameter of the nipple (SB) is determined by analysing the following conditions: If RB is not defined, or: RB > RA or (RA - RB > NGD + RC) then: LMOD = RA - RC SB = LMOD - NGD

3)

In other cases, the previous conditions are re-applied, decreasing the NGD to adjust the calculations. The minimum values which can be reached by the NGD are:

• • • 4)

0.042ins for tubing OD < 3.313ins 0.050ins for tubing OD < 5ins 0.070ins otherwise.

The data obtained are then used to match the nipple. nipple. To select the nipples nipples to be as compatible as possible with the available options in the suppliers catalogues, an approximation of 1/100ins for SB is acceptable.

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In the event of achieving a good match, the nipple is compared with the data from the catalogue. If there is no nipple with the characteristics required, there are two options:

• • 2)

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Produce a new nipple size Select the maximum nipple diameter from the catalogue < SB.

The type of nipple (e.g. F) is obtained from the previous previous selection. If F is chosen, it is then possible to use an R type nipple if the following conditions exist:

• •

The nipple in question is not required for the installation of a W/L retrievable backup SCSSV The subsequent nipple must be type F with the following characteristics:

SB(F) < SB(R) LMOD(F) + 0.050 < no-go ID(R). 8.4.2.

Selective Nipple Nipple Configuration

Criteria similar to those detailed in the tapered nipple procedure are used to choose the tubing hanger nipple, i.e. the maximum diameter nipple which is compatible with the rated pressure of the Christmas tree is selected. For the subsequent nipples, the previous size is selected but only for a maximum of three nipples in series. After this it is necessary to reduce the diameter again. It is a rule that if the spacing between two successive nipples is < 30m, a tapered nipple will be used.

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PERFORATING The objective of perforating a well is to establish communication between the wellbore and the formation by making holes through the casing, cement and into formation in such a manner so as not to inhibit the inflow capacity of the reservoir. To optimise perforating efficiency, it is not solely down to the perforating technique but relies extensively on the planning and execution of the well completion which includes selection of the perforated interval, fluid selection, gun selection, applied pressure differential or underbalance, well clean-up, and perforating orientation. One of the important aspects is the underbalance, which has been proven to significantly help to achieve a post-perforating flow rate to effectively flush out gun debris and remove the crushed zone which surrounds every perforating tunnel. If this is not effective, increased perforating skin can reduce production rates. The advantages of perforated casing wells is already described in section 5.2.3 and offers selectivity, however the perforated volume in the pay is relatively small compared to open hole (+/- 25%), therefore perforation damage is an extremely important aspect. To this end it is necessary to obtain an adequate shot density with a sufficiently deep enough penetration to pass through the drilling damage and maximise flow through each tunnel.

9.1.

SHAPED CHARGE PERFORATING PERFO RATING

The principle of shaped charge perforating is available in any service providers sales and technical literature (Refer to figure 9.a). The important issues for the completion engineer are the charge selection to meet with the conditions and provide the maximum perforating efficiency. o

The explosives for use in most shaped charges up to 300 F is RDX (cyclonite) and above this temperature and depending on time exposed to the temperature, HMX, PS, HNS or PYX is used. The performance of each is available from the suppliers. The detonating cord, which couples all the charges to the detonator in the firing head, must match the explosive selected. The detonator is triggered by electrical heating when deployed on wireline systems or by a firing pin in mechanically or hydraulically operated firing head systems employed on tubing conveyed perforating (TCP) systems.

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Figure 9.A- Perforation Process 9.2.

GUN TYPES

There are four main types of perforating guns:

• • • • 9.2.1.

Wireline Conveyed Casing Guns Through-tubing Hollow Carrier Guns Through-tubing Strip Guns Tubing Conveyed Perforating Guns.

Wireline Conveyed Casing Guns

These types of guns are generally run in the well before installing the tubing, therefore no underbalance can normally be applied although in large size monobore type completions some sizes can be run similar to through-tubing guns using an underbalance. The advantage of casing guns over the other wireline guns are; high charge performance, minimal debris, low cost, highest temperature and pressure rating, high mechanical and electrical reliability, minimal casing damage, instant shot detection, multi-phasing, variable shot densities of 1-12spf, speed and accurate positioning using CCL/Gamma Ray.

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Through-Tubing Hollow Carrier Guns

These are smaller versions of casing guns which can be run through tubing, hence have o lower charge sizes and, therefore performance, than all other guns. They only offer 0 or o 1 7 180 phasing with a max. of 4spf on the 2  / 8” OD gun and 6spf on the 2  / 8” OD gun. Due to the stand-off from the casing which these guns may have, they are usually fitted with decentralising/orientation devices. 9.2.3.

Through-Tubing Strip Guns

These are semi-expendable type guns and consist of a metal strip into which the charges are mounted. The charges have higher performance and are much cheaper than throughtubing carriers guns, however they also cause more debris, casing damage and have less o o mechanical and electrical reliability. They also provide 0 or 180 phasing. A new version called the ‘pivot gun’ has even larger charges for deep penetration which pivot out from a vertical controlled OD to the firing position. Due to the potential of becoming stuck through strip deformation, they must have a safety release connection so they can be left in the well. They have a particular application for perforating through DST strings and reperforating completed wells. By being able to be run through the tubing, underbalance perforating can possibly be adopted but only for the first shot. Subsequent runs would need the well to be flowed to cause a differential pressure. 9.2.4.

Tubing Conveyed Perforating

TCP guns are a variant of the casing gun which can be run on tubing, therefore, allowing much longer lengths to be installed. Lengths of over 1,000ft are possible (and especially useful for horizontal wells) and perforating under exceedingly high drawdowns is possible with no risk to the guns being blown up the hole. In completion operations, they may be deployed and hung-off in position before installation of the completion string, run on the bottom of the completion packer or run through the tubing on coiled tubing. Alternately they can be run in long lengths for overbalance perforating before completion string installation. Normally the completion is displaced to an underbalance fluid, then the guns detonated by either:

• • • •

A bar dropped from surface Hydraulic pressure applied from surface then subsequently reduced to the planned underbalance pressure during a time delay. Hydrostatic pressure reduction. Impact by a wireline deployed tool.

Another version available, normally used on well tests, is where a differential is applied between the annulus and the sump via porting through the test packer.

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The main problems associated with TCP are:

• • • •

Gun positioning is more difficult The sump needs to be drilled deeper to accommodate the gun length if it is dropped after firing A misfire is extremely expensive Shot detection is more unreliable.

Due to the longer exposure time because of the deployment, higher grade charges may also be required. 9.3.

GUN PERFORMANCE

9.3.1.

API And Performance Data

For most completion applications, API RP 43, which includes performance data produced by the suppliers, can be used as a qualitative comparison of charge performance. This provides under two specific tests:

• •

Entrance hole size and penetration length into a 5ft diameter concrete target. Entrance hole, penetration and flow efficiency in a Berea sandstone target at elevated temperatures and an estimated 800psi effective stress.

The performances are listed in two sections I and II. Section II is normally used for comparisons, however the performance in actual use may differ due to differences in rock strength, overburden stress and wellbore pressure and temperatures. The variations for these reasons is non-linear and depends on the type of charge. The API tests are also unreliable as the targets have had differing strengths and porosities and there is no consistent quality control standard for production of the charges. Ageing of explosives, charge alignment, moisture contamination, gun stand-off, the thickness of casing and cement or if multiple casings are to be perforated also has an impact on the gun performance. It is necessary for engineers to obtain as much accurate data from the suppliers and use Eni-Agip historic data in order to be able to make the best choice of gun.

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Guidelines Gravel Pack Completions Completions

Due to the problem of flow restriction discussed earlier in section 2.4.1, the important factors are:

• • • • •

Hole diameter to achieve adequate flow area. Shot density to achieve adequate flow area. Debris removal. Shot phasing. Penetration.

This in conjunction with correct gravel pack procedures is essential for to prevent high skin factors. High Underbalanced TCP Perforating

High drawdowns over 500psi for production wells require, if possible:

• • • •

TCP methods Deep penetrating charges. High shot density over 8spf. o Minimum 90 phasing.

Underbalanced Perforating With Through-Tubing Guns

If TCP costs cannot be justified and if formation perforated skin factor is acceptable, underbalanced perforation can be carried out with through tubing systems. On the first run a high overbalance can be used but on subsequent runs the only means of producing a differential is to flow the well at a rate governed not to blow the gun up the hole. This is affected by the gun weight, type of fluid, bypass area and expected flow rate. The use of these relatively smaller guns require contact with the casing wall, orientation at o o o 90 with 180 phased guns or in line with the contact point if 0 phased. Shot Density

Shot density in homogeneous, isotropic formations should be a minimum of 8spf but must exceed the frequency of shale laminations. If perforating with through-tubing guns, this will require multiple runs. A shot density greater than this is required where:

• • • •

Vertical permeability is low. There is a risk of sand production. There is a risk of high velocities and hence turbulence. A gravel pack is be conducted.

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Penetration

In general, the deeper the shot the better, but at the least it should exceed the drilling damage area by 75mm. However, to obtain high shot density, the guns may be limited to the charge size which can physically be installed which will impact penetration. Phasing o

o

o

o

Providing the stand-off is less than 50mm, 180 or less, 120 ,90 , 60 is preferable. If the smallest charges are being used then the stand-off should not be more than 25mm. If o fracturing is to be carried out then 90 and lower will help initiate fractures. Gun Stand-Off

Gun stand-off should be minimised for improved performance, especially at high pressures. If low phase angle, high density shots are preferred then TCP and casing guns should be used. As a general rule stand-off should never be more than 50mm. Hole Size

The hole size obtained is a function of the casing grade and should be as follows:

• • •

Between 6mm and 12mm for natural completions. Between 15mm and 25mm in gravel packed completions. Between 8mm and 12mm if fracturing is to be carried out and where ball sealers are to be used.

Overbalanced Perforating

If a well is to be perforated overbalanced, then strict control over the fluid used to ensure it is compatible with the reservoir formation, formation fluids and must also be clean to prevent formation damage. 9.3.2.

Underbalanced Perforating

To optimise the perforating clean up, an underbalance should be used. King et al developed a recommended minimum level of drawdown based on a number of field studies where TCP perforating had been employed, (Refer to the Figures below). These guidelines should be used to select the appropriate drawdown for consolidated completions. In unconsolidated sands, the intention is to cause perforation enlargement to remove the crushed zone without collapsing the cavity or sanding in the guns. This requires that less drawdown is exerted during the well clean up. The optimum clean up period is subjective and opinions range from 1gall to 5gall per perforation. The best method of clean up is to flow the well continually for several hours after perforating at normal offtake rates.

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Firing Heads

As described earlier, there are a number of different firing heads for various applications. . Wireline perforating systems are normally electrically trigger by passing an electrical signal down the cable to the guns. However, in TCP systems there are a wide variety including pressure operated, bar drop, wireline activated, etc. Two very important considerations are safety during installation of TCP systems and redundancy in the event of a fault occurring in the primary firing system. Safety

The use of tubing installed hydraulic actuated systems has the problem of how to conduct pressure integrity tests on the completion with sufficient margin between the gun activation pressure and the highest test pressure applied. Obviously, it is undesirable to have a gun actuation pressure higher than the test pressure as a leak may occur while trying to trigger the guns. Protecting the firing head from test pressure is a dangerous procedure as a plug may leak will also cause premature detonation. It is good practice to use a bar drop firing mechanism (deployed on wireline if possible as dropping the bar from surface may damage sensitive completion items) or wireline installed firing heads which can be installed after the completion is set and tested. This provides full safety during gun deployment. Redundancy

This is an important aspect, for if there is a firing head fault, gun recovery would be very costly. Using wireline installed firing heads provides some redundancy in that the first head can be retrieved and a second head deployed. There are other side-by-side systems available which provide a tubing installed pressure activated firer with a secondary receptacle for a wireline installed firer. 9.3.4.

Perforating Procedures

Refer to the ‘Completion Procedures Manual.

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Figure 9.C - Recommended Underbalance for Perforating Gas Zones in Stable Sandstones

Figure 9.D - Recommended Underbalance for Perforating Gas Zones in Stable Sandstones

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Figure 9.E - Recommended Underbalance Underbalance for Perforating P erforating Shallow Unconsolidated Unconsolidated Gas Sands

Figure 9.F - Recommended Underbalance Underbalance for Perforating P erforating Shallow Unconsolidated Unconsolidated Oil Sands

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ARTIFICIAL LIFT The benefits and most commonly used artificial lift were described previously in section 5.6.4. The application of artificial lift simply displaces the TPC curve downwards so that a lower bottom-hole flowing pressure is achieved. In simple terms, the artificial lift injects energy into the system. Energy can also be introduced by reservoir pressure maintenance. Reservoir development optimisations studies are necessary to determine the relative technical and economic benefits of the options and the timing of the investments. In some fields, both pressure maintenance and artificial lift are used which defers the installation. In other cases, artificial lift from the outset is necessary to achieve the production and economic targets. Just as tubing size is critical to high PI wells, then minimisation of the FBHP is critical to low PI, low pressure wells. To summarise the reasons for the installation of artificial lift are to:

• • • • •

Reduce the effects of declining bottom-hole pressures. Offset the effects of increasing water production. Overcome high friction effects of heavy viscous or waxy crudes. Meet with targeted high offtake rates. Kick off high GLR wells that die when shut-in.

The selection of the most appropriate artificial lift system involves a number of factors but mainly on specific well performance. Section 10.7 lists all the systems, their applications, design considerations, limitations and comparisons. Selection of the method is also based upon operating costs and workover frequency costs. System life is difficult to predict as it is a function of operating conditions, e.g. ESP life can vary between days and five years depending on temperature, solids production, GLR and lack of particular experience with the system. Some systems are able to cope better with production problems than others which will obviously affect the choice. Consideration of future artificial lift requirements must be taken during the planning stage, such as casing size, liner top setting, etc. These early decisions can save much expense later, such as:

• • • • • • • •

Casing ID Casing connection in on gas lift Size and positioning of liners Provision of a sump for rod pumpers Pre-positioning of gas lift mandrels for gas lift and ASV system Pre-installation of conduits for hydraulic pumps Parallel bore for plunger lift etc.

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GAS LIFT

The continuous gas lift method adds gas into the producing fluids which reduces the hydrostatic head and, hence the back-pressure on the formation. The injection gas is supplied in a closed loop system in which it is taken from the separators and then compressed, dried if necessary and then delivered to the well (Refer to figure 10.a). The lift gas is normally pumped into the annulus and into the tubing through gas lift valves installed in Side Pocket Mandrels (SPMs). Occasionally the gas is pumped into the tubing and the production taken up the annulus or in the annular space in a concentric completion. Another less common application is Intermittent Gas Lift, also shown in figure 10.a, which is used to produce low volumes of liquid (<350stb/d) from wells with low BHFP (<0.1psi/ft). Due to the low liquid production, it must be produced in slugs by intermittently gas injection through a motorised valve. A standing valve is sometimes necessary to prevent the gas from flowing into the formation. In continuous gas lift, it is desirable to position the lower gas injection point as deep as possible in the well, however this t his is limited by:

• • • •

available gas lift pressure the flowing tubing pressure at the intended offtake rate the depth of the packer and deepest gas lift mandrel the differential required to close the upper valves closed (+/-20psi) and to ensure that injection at the operating operating GLV is stable (between 50 and 500psi)

figure 10.b illustrates the fundamental principle of a gas lift design and operation. As can be seen the gas is injected down the annulus and into the tubing through the topmost valve lightening the fluid column in accordance with the total GLR curve shown. As the fluid gradient changes, the gas moves down to the next valve unloading the casing fluid and as the reaches the second valve and lightens the fluid gradient from that point, the first unloading valve closes so that all the gas passes through the second valve. This continues in sequence for all other valves until reaching the operating valve where the casing pressure will drop below the initial kick-off pressure. During this process the well BHP will drop to the point where the well will flow. Production is determined by:

• • • •

reservoir pressure PI water cut gas injection rate

Once the well reaches a stabilised rate, the injection is optimised to maximise production. As described in section 2.4.3, increasing GLR initially decreases the bottom-hole pressure on the TPC. There is an optimum GLR to produce stabilised flow for a particular tubing size and a minimum BHFP. As GLR requirements are subject to diminishing returns, most gas lift systems are based on available gas supply volumes, Q i, or either the near optimum GLR which provides a BHFP within 20-50psi of the minimum.

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From this it is seen:

• • •

OF 295

Liquid rate, q, is dependent on the IPR and attainable BHFP. Total GLR = Producing GLR + Injection GLR
Figure 10.A - Typical Gas Lift System

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Figure 10.B - Example E xample Gas lift design 10.1.1. Impact On Completion Completion Design

In recent times, much higher gas supply pressures have been used to enable deeper valves to be reached or reduce the number of mandrels and valves required. This increased pressure, however, applies more pressure on the annulus casing, hence gas tight or premium connections are generally selected. Modern gas lift systems usually now use SPMs with wireline GLVs to reduce servicing costs. SPMs have relatively large ODs and this needs to be considered in the casing design. All mandrel depths are taken of the design as TVDs and these must be converted to MD. As the mandrels at deeper depths become increasingly closer, the spacing of them is much more critical. Although gas lift valves incorporate check valves to prevent back flow, these are not reliable and as the annuli contain quite a considerable inventory of gas, an annulus safety system is installed for platform safety. This may again impact on the casing design.

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10.1.2. Common Problems

The worst problem that can arise is that the pressure losses in the gas injection system and slugging have been underestimated and that the valve spacing is too far apart. Operationally, the problems are usually inefficiency through upper gas lift valve or tubing leaks. 10.2.

ELECTRICAL ELECT RICAL SUBMERISBLE PUMPS

ESPs greatest application is in moving large volume of low GOR (<100scf/stb) fluids. They are particularly popular for high rate undersaturated oil wells, high water cut wells and water supply wells. Their main limitation is gas production but improved downhole separators and procedures can now handle GORs up to 1,000scf/stb. ESPs performance is best at stable conditions within +/-25% of the optimum rate. Versions with variable frequency drives (VFD) are available or the use of surface chokes can be used to increase the band of rate (50-190%) but incur higher capital and operating costs. The construction of the ESP is a multi-staged centrifugal connected through a short shaft to the downhole electric motor. Each stage consists of a rotating impeller and stationary diffuser. The differential pressure or total dynamic head (TDH) developed by the pump is a function of the pump flow rate which is relative to the head developed by each stage and obtainable from manufacturers publishing’s. TDH=Ns Hs

Eq. 10.A

where: NS HS

= =

number of stages head per stage

The pump characteristics are based on constant rotational speed which is dependent on the AC supply frequency, 3,500 rpm at 60 Hertz and 2,915 at 50 Hertz. Due to these high speeds and pump construction it is obvious that sand production is very detrimental and that emulsions are easily formed. To prevent sand production it is sometimes necessary to install a gravel pack or pre-packed screen for pump protection. The ESP delivery capacity will vary according to:

• • • •

Well IPR Reservoir pressure Surface back-pressure Electrical supply frequency

figure 10.c shows the most common types of ESP installations and the pump components. Surface equipment usually includes a three phase transformer, motor controller and a wellhead pack-off for the cable. If possible, the installation should be designed to facilitate downhole separation of free gas and vented up the annulus which is necessary when the gas volume exceeds the pump operating limit (typically +/-10% of the total fluid volume). On offshore installations, gas production up the annulus may be a significant problem.

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As can be seen from the schematic, most pump installations are on the end of tubing and positioned above the perforations or open hole. The motor is situated at the bottom of the assembly so that the well flow around the motor will dissipate the heat generated. If the pump has to be positioned below the interval, a shroud is used to draw the produced fluid down past the motor. Bottom discharge pumps are used in powered dump flood wells.

Figure 10.C- Typical ESP Installations Installations

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Other less common deployment methods are:

• •

Suspended on the cable and latched into a downhole receptacle. On coiled tubing with the cable through the coil which is terminated with a special wellhead arrangement.

Both of these suffer from some problems such as cable failures with the cable suspension method and well control issues with the C/T mounted method (i.e. downhole safety systems if the well can flow naturally). A recent development with the later is in Norway where downhole safety is satisfied by the installation of shear seal capability below the coiled tubing hanger. 10.2.1. ESP Performance

It is normal procedure to select the largest pump that will fit into the production casing (especially if this was catered for in the planning stage). Small casing or liners will obviously limit the pump size selection. ESP sizes and capacities are shown in table 10.j below.

Casing Size, ins

Pump OD, ins

Motor OD, ins

Rate, stb/d

Power, HP

TDH, ft

4  / 2

1

3. 3 75

3 . 750

100-1,900

50-125

5,000-12,000

1

5  / 2

4. 0 00

4 . 500

200-5,000

100-300

5,000-12,000

7

5.625

5 . 437

1,000-16,000

200-650

5,000-12,000

5

8  / 8

6. 7 50

7 . 375

4,000-26,000

400-850

3,000-10,000

3

8. 6 25

N/A

12,000-33,000

500-1020

2,000-5,000

3

11 . 25 0

N/A

24,000-100,000

500-1030

500-3,500

10  / 4 13  / 8

Table 10.J - ESP Capacity Ranges

Two approaches are commonly used to evaluate an ESP system: 1)

2)

Pre-select the production target and corresponding BHFP and determine the TDH and pump size and depth required to meet this rate. This often carried out by plotting the pressure traverses above and below the pump (Refer to figure 10.d). Pre-select the maximum pump horsepower, or number of stages, and determine the attainable pump rate with:

• •

a fixed IPR and various tubing sizes a fixed tubing size and various IPR options

In this approach the pump performance curve is often plotted below the system performance curves. An example this to optimise the number of stages for a maximum pump HP is shown in figure 10.e.

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Figure 10.D - Example ESP Design for a Pre-selected Rate

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Figure 10.E- Example ESP Design for a Pre-selected Pr e-selected HP

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10.2.2. Impact On Completion Completion Design

The key to an efficient ESP design is heat removal and insulation material selection for the actual operating temperatures and environment, especially when temperatures are in the o region of 250 F. The clearance between the pump and the casing should be small enough that a flow velocity of a minimum of 1ft/sec is achieved. In large casings, a shroud must be used to provide this rate. Centralisation of the pump is also critical. The pump should be set in a straight section of casing to avoid bending and the cable needs to firmly attached to the tubing for support by cable clamps (two per joint). Centralisation and crush resistant clamps should be installed across doglegs. When re-completing a ESP well the pump should be moved slightly from the original position to help minimise any casing corrosion due to eddy currents. Casing design is obviously has a large impact on the completion design or in the case of an ESP completion, vice versa. Also consideration must be given to the optimum tubing size and cable dimensions to ensure they can be accommodated in the casing. The completion design is also affected if downhole separation is required in conjunction with downhole safety. Tubing hanger and penetration systems for packers have been well developed now for fast easy installation with the testing of the connections carried beforehand in the workshop. If properly planned an ESP completion only requires one onsite termination. 10.2.3. Common Problems

The biggest problem with ESP completions is short running time before failure with the cost impact for re-completion. However, ESP systems are becoming evermore reliable. The most common problems are due to:

• • • • • • • •

Bad installation procedures. Inadequate system analysis leading to the system operating outside the range. Unsuitable cable insulation material for the conditions. Too much free gas and no enlarged intakes stages. Sand production. Too many frequent start ups when there is no soft start facilities. Scaling up of the impellers. Poor voltage supply stability.

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HYDRAULIC HYDRAULIC PUMPING SYSTEMS SYSTE MS

Hydraulic pumping systems are attractive alternative to ESP systems where there is high temperatures, depth, deviation or severe operating environments. The downside is the requirement for two reasonably large conduits to minimise fluid pressure losses, maintaining a clean solids free power fluid and the high capital and operating costs. It is also popular where there is insufficient gas for a gas lift system and is a viable alternative to rod pumps for deep (>8,000ft) wells. The two simplest and common systems are the Jet Pump and the Piston Pump which are interchangeable in most instances which provides great flexibility in coping with changeable well conditions. The pumps can be installed and retrieved by wireline or pumping method using swab cups, hence providing lower servicing costs. The conduits for the power fluid and returns can be the annulus with a single tubing, however this exposes the annulus to potential corrosion so, if this is a problem, dual tubing strings can be used either parallel or concentric. The annulus is sometimes required for gas venting and in this case a dual string is required. Piston Pump

The piston pump is a reciprocating pump operated with a drive piston which automatically shuttles backwards and forwards exhausting the spent power fluid into the returns. In effect the piston pump is equivalent to the rod pump except that the pump drive is subsurface but can produce up to 8,000stb/d although it is normally used to produce <2,000stb/d. Their application is commonly for deviated wells between 8,000-18,000ft although high surface power fluid pressures are required below 12,000ft. There is flexibility in the system as pump rates are controlled by controlling the power fluid supply rate. There is a large selection of pump sizes/stroke length available for a wide range of operating conditions. Jet Pump

The jet pump uses no moving parts and imparts momentum into the fluid using the venturi effect with a jet, throat and diffuser. The size of the these can be varied to pump volumes of 1 100-15,000stb/d although free pump systems are limited to 8,000stb/d with 4  / 2” tubing. To prevent cavitation, it is recommended to submerge the pump by at least 20% of the TDH so is better suited to respectfully productive, or restricted offtake target wells. As there is no moving parts, the pump is not as sensitive to damage and lower quality power fluids can be used and can be used in higher GOR wells up to 3,000scf/stb. However pump efficiency is low at 33-66% and large production rates can only be achieved in high rate installations. Pump performance is a complex function of GOR, pump intake pressure, supply pressure and rate. Optimisation is generally through using supplier’s computer software. A preliminary calculation of the pump intake or output curve can be made by hand. The maximum attainable performance have been summarised in table 10.k below.

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Head Ratio

Flow Ratio

0. 45

0. 5

0. 25

1. 0

0. 17

1. 5

0. 10

2. 0

Table 10.K- Jet Pump Maximum Performance

In table 10.k above:  Head Ratio = Flow Ratio =

pump pump outpu outputt pressu pressure re − pump pump inlet inlet pressu pressure re downh downhole ole power power fluid fluid pressu pressure re − pump pump outp output ut pressure pressure reservoir reservoir production production rate  power fluid rate

Often the maximum power fluid supply pressure and rate is fixed by surface equipment rating, e.g. p <5,000psi, <5,000psi, q PF  PF  <4,500stb/d. When calculating bottom hole pressures, the completion configuration and power fluid rate to the production to obtain the total discharge rate. The pump intake curve (PIC) can then be generated using table 10.k above plotted against well IPR (Refer to figure 10.f).

Figure 10.F- Example Jet Pump Design Curve

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Turbine Pumps

The hydraulic turbine pump developed by Weir Pumps is an alternative to the ESP for producing very large volumes of fluid, 2,000-100,000stb/d. It has the same principle of operation as the ESP but the motor is replaced by a hydraulic turbine which rotate the shaft at 5,000-10,000rpm. This provides higher lift capacities (head and volume) per stage, therefore the units are much shorter approximately 10% of the ESP. The operating range is much greater as the pump can be controlled by varying the supply pressure giving 10-100% rate and 20-50% TDH at reduced rates. Their reliability is still suspect due to the high rotating speed and metallurgy problems. 10.3.1. Impact On Completion Completion Design

The casing size is obviously important here to accommodate the pump size and perhaps two tubing strings. Sometimes concentric completions are preferred or the annulus is used but consideration must be given to potential corrosion due to oxygen in the power fluid. Like the piston pump solids free power fluid is essential. Like the ESP, gas venting may be necessary which would require a third conduit (generally the annulus). Occasionally the DHSV is controlled by pressure from the pump. 10.4.

ROD PUMPS

The most common pumping system on low rate land wells is the rod or beam pumping. It is usually limited to shallow wells (<8,000ft) producing less than 500stb/d although they can produce up to 2,000stb/d. The system consists of three elements, the downhole pump assembly, the sucker rod and the surface pumping unit. The annulus is usually left open and used to vent any free gas that is separated downhole. Tubing is used as the production conduit and contains the rods preventing wear and corrosion to the annulus. The tubing is usually anchored to the casing and pulled into tension to reduce tubing movement, buckling and, hence rod wear. There are two versions of bottom-hole pump, the tubing retrievable barrel and the rod retrievable barrel. The tubing pump requires the tubing to be pulled to retrieve the barrel and the rod pump barrel is retrieved when pulling the rods. The tubing pump has the largest capacity but is more costly to repair than the rod pump which is the most common. The pump displacement, PD , is defined by the plunger stroke, S P  P,  and the pump speed, N , the plunger diameter, D and the amount of liquid fillage and/or slippage past the plunger, E P  P  = 0.7 to 9.5. 2

PD = Ct x Sp x N x D x Ep Eq. 10.B

where: EP Ct

= =

Pump ef ficiency 2 Corr orrecti ection on fact factor or 0.11 0.1166 66 for for oi oilfiel field d uni units ts,, (i (in, spm, pm, in in , stb/d)

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Figure 10.G- Typical T ypical Rod Pumping System

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As the rod suffers from stretch and dynamic forces, S P  P  will not be the same as the stroke at surface, S , therefore load-displacement plot forms the basis for pump design and analysis. The fluid load, F o  o,  carried by the rods on the upstroke is dependent on the net lift, H , which is the vertical distance from the operating fluid level (OFL) in the annulus to surface plus the equivalent head of any surface back-pressure. It also depends on fluid SG or density. API recommends ignoring the area of the rods when calculating this load: 2

Fo = Ct x SG x D x H where: Ct

=

2

0.340 in oilfie field units (SG, in , ft, lbs)

This load can be estimated from dynamometer surveys, which measure the rod load versus displacement at the surface and serves the most effective means of diagnosing pump problems. As the loads on the polished rod includes fluid load, dynamic forces and rod weight, the rod weights may be relatively large in deep wells and in these cases a tapered rod string is preferred where the rod diameter is larger with increasing load. Buoyancy varies throughout the cycle but it is generally taken on the downstroke when the travelling valve is open. Acceleration and friction are also factors in dynamic loading with the peak polished rod load on the upstroke will be significantly higher than the sum of the rod and fluid loads. Similarly, on the downstroke, the minimum will be less than the buoyant weight of the rods. Pump stroke efficiency is a function of pump speed and rod loading. The dynamics also cause the rods to oscillate harmonically like a stiff spring. Typical pumping speeds are 8 to 15spm which amounts to 4.2 to 7.9 million cycles per year, therefore the rod design must focus on minimising fatigue failures which is exacerbated by corrosion in the operating environment. The surface pump unit is usually a beam type although other concepts have been developed. The surface prime mover and gearbox have been developed over the years to cater for the rod pump to reduce failures. System design is very complex and is an iterative process normally carried out by computer software. API have produced a programme to generate a set of design curves published in API RP11L and provided some general results in Bulletins 11L3 and 11L4 which are a useful starting point for design. However, in 11L4, API used 100% efficiency and pump rates which are higher than those generally found in the field, therefore, it is advisable to enter a curve which is 100 to 200% of the intended target for scoping out the required o equipment capacity. It is also not reliable for heavy oil wells (<20 API) unless correction factors are applied for fluid vicosities and lack of rod weight on the downstroke. Rod fall problems often cut restrict pump rates to 1.5 to 2.5spm which lead the use of long stroke pumps. Sand problems are often a problem with high viscous crudes which increase wear of the pump parts.

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10.4.1. Impact On Completion Completion Design

If free gas is expected then a packer should not be installed to allow the gas to vent up the annulus if it is planned to convert a completion to rod pump lift within a few years unless required for zonal isolation. If a well has to be pumped which is below the bubble point, it is advised to set the pump below the producing interval to aid gas separation, maximise drawdown and minimise perforation blocking by fill. If a well is fractured, the pump must be set above the perforations as frac sand can damage the pump. The casing geometry must be sufficient enough to enable the gas to percolate through the fluid column against the down-flow. 10.5.

SCREW PUMP SYSTEMS

Screw or progressive cavity pump is a rotary positive displacement pump consisting of a rubber stator and stainless steel rotor. The rotary drive to the downhole pump is through sucker rods from a prime mover through a gearbox. They rates of between 5 to 500stb/d, although in some circumstances capacities of 1,500stb/d is possible, on heavy oil wells or viscous emulsions where conventional rod pumps are hindered by rod fall. They have an advantage in that they can handle some sand production and less costly. The production rate is proportional to the rotary speed and are determined from manufacturers charts, generally between 50-100rpm in heavy oil and 500rpm in light oils. The selection of the material for the rubber stator is the key for operational life in the well environment. 10.6.

PLUNGER PLUNGER LIFT

Plunger lift are used on high GLR wells that produce liquids at relatively low rates (<500stb/d). The tubing/casing annulus is used to store gas energy provided to the tubing when the well is opened up. This energy is used to drive the plunger up to surface carrying a small slug of liquid. After production of the following tail gas when the liquid begins to kill the well the plunger is dropped again and the cycle repeated. It is particularly useful for de-watering gas wells. Operating requirements are:

• • •

GLR >500scf/stb PI <1stb/d/psi Plunger velocity 700 to 1,000ft/min

Efficiency of this system decreases with depth and PI but increases with tubing size. It is essential that the completion tubing is parallel and drifted to ensure correct operation of the plunger.

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Figure 10.H- Typical Screw S crew Pump Installation

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Figure 10.I - Typical Plunger Lift Installation

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SUMMARY SUMMARY ARTIFICIAL LIFT SELECTION SELECT ION CHA CHARTS RTS

10.7.1. Design Considerations Considerations And Comparisons Comparisons Consideration

Rod Pumping

Screw Pumping

ESP

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

Capital Cost

Low to moderate increase with depth and larger units.

Low increase with depth and larger rates.

Relatively low capital cost if commercial electric power available. Costs increase as horsepower rises.

Varies but often competitive with rod pumps. Multiple well, central systems reduce cost per well but is more complicated.

Competitive with rod pump. Cost increases with higher horsepower.

Low well equipment costs but lines and compression costs may be high. Central compression system reduces cost per well.

Same as continuous flow gas lift.

Very low, only low cost well equipment if no compressor required.

Downhole Equipment

Reasonably good rod design and operating practices needed. Data bank of rod and pump failures beneficial. Good selection, operating and repair practices needed rods and pump.

Good design and operating practices needed. May have problems with selection of appropriate stator elastomer.

Requires proper cable in addition to motor, pumps, seats, etc. Good design plus good operating practices essential.

Proper design plus good operating practices essential. requires powerful conductor. Free pump and choose powerful option.

Requires computer design programme for sizing. tolerant to moderate solids in power fluid. No moving parts in pump. Long service life and simple repair procedures.

Good valve design and spacing essential. Moderate cost for well equipment (valves and mandrels). Choice of wireline retrievable retrievable or conventional valves.

Unload to bottom with gas lift valves. valves. Consider chamber or high PI and low BHP wells.

Operating practices have to be tailored to each well for optimisation. Some problems with sticking plungers.

Efficiency (output hydraulic HP divided by input HP)

Excellent total system efficiency. Full pump fillage efficiency typically about 50-60% feasible if well is not over-pumped.

Excellent. May exceed rod pumps for ideal cases. Reported system efficiency 5070%. More operating data needed.

Good for high rate wells but decreases significantly for <1,000 BFPD. Typically total system efficiency is about 50% for high rate well but for <1,000 BID, efficiency typically is 40%.

Fair to good, not as good as rod pumping owing to GLR, friction and pump wear. Efficiencies range from 3040% with GLR >100. May be higher with lower GLR.

Fair to poor. Maximum efficiency only 30%. Heavily influenced by power fluid plus production gradient. Typically operating efficiencies of 10-20%.

Fair increases for wells that require small injection GLRs. Low wells for wells requiring high GLRs. Typical efficiencies at 20% but range from 5-30%.

Poor, normally requires a high injection gas volume/bbl fluid. Typical lift efficiency is 1050% improved with plungers.

Excellent for flowing wells. No input energy required because it uses the well. Good even when small supplementary gas is added.

Flexibility

Excellent, can alter stroke speed, length, plunger size and run time to control production rate.

Fair, can alter speed. Hydraulic unit provides additional flexibility but at added cost.

Poor. Pumps usually run at a fixed speed. Requires careful sizing. VSD provides more flexibility but added costs. Time cycling normally avoided. Must size pump properly.

Good to excellent. Power fluid rate and speed of downhole pump. Numerous pump sizes and pump/engine ratios adapt to production and depth needs.

Good to excellent. Can vary power fluid rate and pressure adjusts the production rate and lift capacity. Selection of throat and nozzle sizes extend range of volume and capacity.

Excellent. Gas injection rate varied to change rates. Tubing needs to be sized correctly.

Good, must adjust injection time and cycles frequently.

Good for low volume wells. Can adjust ingestion time and frequency.

Miscellaneous problems

Stuffing box leakage may be messy and a potential hazard. Anti-pollution stuffing boxes are available.

May have limited service in some areas. Because this a newer method, field knowledge and experience are limited.

Requires a highly reliable electric power system. Method sensitive to rate changes.

Power fluid solids control essential. Need 15ppm of 15 µm particle size max. to avoid excessive engine wear. Must add surfactant to a water power fluid for lubrication. Triplex plunger leakage control required.

More tolerant of power fluid solids, 200ppm of 25µm particle size acceptable. Dilutents may be added if required. Power water (fresh, produced or seawater) acceptable.

A highly reliable compressor with 95+% run time required. Gas must be dehydrated properly to avoid gas freezing.

Labour intensive to keep time tuned otherwise poor performance. maintaining steady gas show often causes injection gas measurement and operating problems.

Plunger hangup or sticking may be a major problem.

Table 10.L - Design Considerations and Overall Comparisons Comparisons (pg1)

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Screw Pumping

ESP

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

Operating Costs

Very low for shallow to medium depth (<7,500ft) and locations with low production (,400BFPD).

Potentially low but short run life on stator or rotor frequently reported.

Varies, if HP is high, energy costs are high. High pulling costs result from short run life. Other repair costs are high.

Often higher than rod pump even for free systems. Short run life increases total operating costs.

High cost owing to HP requirement. Low pump maintenance cost typical with properly sized throat and nose.

Well costs low. Compression costs vary on fuel cost and compressor maintenance. Key is to inject as deeply as possible with optimum GLR.

Same as continuous flow gas lift.

Usually very low,

Reliability

Excellent. Run time efficiency >95% if good operating practices are adopted and corrosion, wax asphaltenes, solids, deviations, etc., are controlled.

Good. Normally over-pumping and lack of experience decreases run time.

Varies. Excellent for ideal gas lift cases, poor for problem areas. Very sensitive to operating temperatures and electrical malfunctions.

Good with a correctly designed and operated system. Problems or changing well conditions reduce downhole pump reliability. Frequent downtime results from operational problems.

Good with proper throat and nose sizing for the operating conditions. Must avoid operating in cavitation range of jet pump throat, related to pump intake pressure. More problems if pressures >4,000psig.

Excellent if compression system is properly designed and maintained.

Excellent if there is an adequate supply of ingestion gas and adequate low pressure storage volume for injection gas. System must be designed for the unstable gas flow rates.

Good if well production is stable.

Salvage Value

Excellent, easily moved and good market for used equipment.

Fair to poor. Easily moved and some current market for used equipment

Fair. Some trade in value. Poor open market values.

Fair market for triplex pumps, good value for wellsite system that crane can move easily.

Good. Easily moved. Some trade in value. Fair market for triplex pump.

Fair. Some market for good used compressors and some trade in value for mandrels and valves.

Same as continuous flow gas lift.

Fair. Some trade in value. Poor open market value.

System (total)

Straightforward and basic. procedures to design, install and operates following API specifications and recommended practices. Each well needs an individual system.

Simple to install and operate. Limited proven design, installation and operating specifications Each well needs an individual system.

Fairly simple to design but requires good rate data. System not forgiving. Requires excellent operating practices. Follow API recommended practices in design, testing and operation. Typically each well is an individual producer using a common electric system.

Simple manual or computer design, typically used. Free pump easily retrieved for servicing. Individual Individual w ell unit very flexible but extra cost. Requires attention. Central plant more complex, usually results in test and treatment problems.

Computer programme typically used for design. Basic operating procedures needed for downhole pump and wellsite unit. Free pump easily retrieved for onsite repair or replacement. Downhole jet often requires trial and error to arrive at best/optimum  jet.

An adequate volume, high pressure, dry non-corrosive and clean gas supply source is needed throughout the entire life. System approach needed. Low back-pressure beneficial. Good data needed for valve design and spacing. API specifications and design/operatin g recommended practices should be followed.

Same as continuous flow gas lift.

Individual Individual wel l or system. Simple to design, install and operate. Requires adjusting and plunger maintenance.

Usage/ Outlook

Excellent. Used on about 85% of US artificial lift wells. The normal standard artificial lift method.

Limited to relatively shallow wells with low rates. Used on less than 0.5% of US lifted wells. Used primarily on gas well dewatering.

An excellent high rate artificial lift system. Best suited for <200oF and >1,000BFPD rates. Most often used on high water cut wells.

Often used as a default artificial lift system. Flexible operation, wide rate range suitable for relatively deep, high volume, high temperature deviated oil wells. Used on <2% of US lifted wells.

GOR try higher volume wells requiring flexible operation. System will tolerate wide depth ranges, high temperatures, corrosive fluids, high GOR and significant sand production. Used on <1% of US lifted wells. Sometimes used to test wells that will not flow offshore.

Good, flexible, high rate artificial lift system for wells with high bottom-hole pressures. Most like a flowing well. Used on about 10% of US lifted wells, mostly offshore.

Often used as a default artificial lift method in lieu of sucker rod pumps. Also a default for low bottom-hole pressure wells on continuous gas lift. Used on <1% of US lifted wells.

Essentially a low liquid rate, rate, high GLR lift method. Can be used for extending flow life or improving efficiency. Ample gas volume and/or pressure needed for successful operation. Used on <1% of US lifted wells.

Table 10.M 10. M - Design Considerations and Overall Comparisons (Pg2)

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10.7.2. Operating Conditions Summary Consideration

Rod Pumping

Screw Pumping

ESP

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

Casing size limits (restricts tubing size)

Problems only in high rate wells requiring large plunger pumps. Small casing size (4.5 and 5.5ins) may limit free gas separation.

Normally no problem for 4.5ins casing and larger but gas separation may be limited.

Casing size will limit use of large motor and pumps. Avoid 4.5ins casing. Reduced performance inside 5.5ins casing depending on depth and rate.

Larger casing required for parallel free or closed systems. Small casing (4.5 and 5.5ins) mat result in excessive friction losses and limits production rate.

Small casing size often limits producing rate owing to high (unacceptable) friction losses. Larger casing may be required if dual strings run.

The use of 4.5 and 5.5ins casing with 2ins nominal tubing normally limits rates to <1,000stb/d. For rates >5,000stb/d use >7ins casing and >3.5ins tubing needed.

Small casing (4.5 and 5.5ins) normally is not a problem for this relatively low volume lift.

Small casing suitable for this low volume lift. Annulus must have adequate gas storage volume.

Depth limits

Good, rods of structure may limit rate at depth. Effectively about 500stb/d at 7,500ft and 150stb/d at 15,000ft.

Poor, limited to relatively shallow depths, possibly 5,000ft.

Usually limited to motor HP or temperature. Practical depth about 10,000ft.

Excellent, limited by power fluid pressure (5,000psi) or HP. Low volume, high lift head pumps operating at depths to 17,000ft

Excellent, similar limits as reciprocating pump. Practical depth of 20,000ft.

Controlled by system injection pressure and fluid rates. Typically for 1,000stb/d with 2.5ins nominal tubing. 1,440psi lift system and lift system and 1,000 GLR, has an injection depth of about 10,000ft.

Usually limited by fallback, few wells >10,000ft.

Typically <10,000ft.

Intake Capability

Excellent, <25psig feasible provided adequate displacement and gas venting. Typically about 50 to 100psig.

Good, <100psi provided adequate displacement and gas venting.

Fair. if little free gas (i.e. >250psi pump intake pressure). Poor if must handle >5% free gas.

Fair but not as good as rod pumping. Intake pressure <100psig usually results in frequent pump repairs. Free gas reduces efficiency and service life.

Poor to fair, >350psig to 5,000ft with low GLR. Typical design targets 25% submergence.

Poor restricted by the gradient of the gas lifted fluid. Typically moderate rate is limited to about 100psi/1,000ft injected depth. Thus the backpressure on 10,000ft well may be >1,000psig.

Fair when used without chambers. PIP >250psi for 10,000ft well. Good when used with chamber. PIP of <250psi feasible at 10,000ft.

Good, bottomhole pressures <150psi at 10,000ft for low rate, high GLR wells.

Noise Level

Fair, moderately high for urban areas.

Good with the surface prime mover causing the only noise.

Excellent with low noise. Often preferred in urban areas if production rate is high.

Good low well noise. Wellsite power fluid units can be sound proofed.

Same as piston pump.

Low at well but noisy at compressor.

Same as continuous flow.

Low.

Obtrusiveness

Size and operation are drawbacks in populated and farming areas. Special low profile units are available.

Good low profile surface equipment.

Good low profile but requires transformer bank. Transformer may cause problems in urban areas.

Fair to good wellhead equipment has low profile. Requires surface treating and high pressure pumping equipment.

Same as piston pump.

Good low profile but must provide for compressor. Safety precautions must be taken for high pressure gas lines..

Same as continuous flow.

Low.

Prime mover flexibility

Good, both engines or motors can be used easily. Motors are more reliable and flexible.

Good, both engines or motors can be used.

Fair, requires a good power source without spikes or interruptions. Higher voltages can reduce I 2R losses

Excellent. Prime mover can be electric motor, gas or diesel fired engines or motors.

Same as piston pump.

Good, engines, turbines or motors can be used for compression.

Same as continuous flow.

None normally required.

Surveillance

Excellent, can be easily analysed based on well test, fluid levels, etc. Analysis improved by use of dynamometers and computers.

Fair, analysis can be based on production and fluid levels only. Not possible to use dynamometers and pump-off cards.

Fair based on electrical checks but special equipment needed otherwise.

Good to fair. Downhole pump performance can be analysed from surface power fluid rate and pressure, speed and producing rate. Bottom-hole pressure obtained with free pumps.

Same as piston pump.

Good to excellent. Can be analysed easily. Bottomhole pressure and production log surveys easily obtained. Optimisation and computer control being tried.

Fair but complicated by standing valve and fallback.

Good but depends on good well test and pressure charts.

Table 10.N - Operating Conditions Summary Summary

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Rod Pumping

Screw Pumping

ESP

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

Testing

Good, Well testing is simple with few problems using standard available equipment and procedures.

Good, same as rod pumping.

Good, Well testing is simple with few problems. High water cut and high rate wells may require a free water knock-out.

Fair. Well testing with standard individual well units presents few problems. Well testing testing with a central system is more complex requiring accurate power fluid measurement.

Same as piston pump. Three stage production tests can be conducted by adjusting production step rates. A pressure recorder must be used to monitor intake pressures.

Fair. Well testing complicated by injection gas volume/rate. Formation GLR obtained by subtracting injected gas from total produced gas. Gas measurement errors are common.

Poor. Well testing complicated by injection gas volume/rate.. Measurement of both input and outflow gas is a problem. Intermittent flow can cause operating problems with separators.

Well testing is simple with few problems.

Time cycle and pump-off controller’s application

Excellent if well can be pumpedoff.

Good. Avoid shutdown in high viscosity/sand producers.

Poor. Soft start and improved seals and protectors recommended.

Poor, is possible but not normally used. Usually controlled only by displacement checks. Pumpoff control not developed.

Poor. Does not appear applicable owing to intake pressure requirement higher than pump-off.

No t a pp pp lili ca cab le le.

P oo oor . C yc yc le le must be periodically adjusted. Labour intensive

Not applicable.

Table 10.O - Operating Conditions Summary Summary (Pg2)

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10.7.3. Artificial Artificial Lift Considerations Consideration

Rod Pumping

Screw Pumping

ESP

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

Corrosion/ scale handling ability

Good to excellent. frequently for both corrosion and scale control.

Good. Batch treatment inhibitor used down annulus feasible.

Fair. Batch inhibition treatment only to intake unless shroud is used.

Good to excellent. Batch or continuous inhibition treatment can be circulated with power fluid for effective control.

Good to excellent. Inhibitor mixed with power fluid mixes with produced fluids at entry of jet pump throat. Batch treat down annulus is feasible.

Good. Inhibitor in the injection gas and/or batch inhibiting down tubing feasible. Steps must be taken to avoid corrosion in injection gas lines.

Same as continuous flow.

Fair. Normal production cycle must be interrupted to batch treat the well.

Crooked/ deviated holes

Fair, increased load and wear problems. High angle deviated holes (>70o) and horizontal wells are being produced. Some success in pumping 15o /100ft using rod guides.

Poor to fair. Increased load and wear problems. Currently very few known installations.

Good. Few problems. Limited experience in horizontal wells. Requires long radius wellbore bends to get through.

Excellent if tubing can be run in the well. Pump will normally pass through the tubing. Free pump retrieved without pulling tubing. Feasible operation in horizontal wells.

Excellent, short pump can pass through doglegs up to 24 o /100ft in 2ins nominal tubing. Same condition as hydraulic piston pump.

Excellent. Few wireline problems up to 70o deviation for wireline retrievable valves.

Same as continuous flow.

Excellent.

Dual application

Fair. Parallel 2x2ins low rate dual feasible inside 7ins casing. Dual inside 5ins casing currently not in favour. Gas is a problem for lower zone. Increased mechanical problems.

No known installations.

No known installations. Larger casing would be needed. Possible running and pulling problems.

Fair. Three string nonvented applications have been achieved with complete isolation of production and power fluid from each zone. Limited to low GLRs and moderate rates.

Same as piston pump except it can possibly handle higher GLRs but at reduced efficiency.

Fair. Dual gas lift is common but good operating of dual lift is complicated and inefficient resulting in reduced rates. Parallel 2x2ins nominal tubing inside 7ins casing and 3x3ins tubing inside 95 / 8ins casing feasible.

Same as continuous flow.

No none installations.

Gas handling ability

Good if can vent and use natural gas anchor with properly designed pump. Poor if must pump >50% free gas.

Poor if it must pump any free gas..

Poor for free gas >5% through pump. Rotary gas separators helpful if solids not produced.

Good to fair. Concentric fixed pump or parallel free permits gas venting with suitable downhole gas separator below pump intake. Casing free pump limited to low GLRs.

Similar to piston pump. Free gas reduces efficiency but helps lift. Vent free gas if possible. Use a gas anchor.

Excellent. Produced gas reduces need for injection gas.

Same as continuous flow

Excellent.

Offshore application

Poor. Must design for unit size, weight and pulling unit space. Most wells are deviated and typically produce sand.

Poor. May have some special application offshore, however a pulling unit is needed.

Good. Must provide electrical power and service pulling unit.

Fair. Feasible operation in highly deviated wells. Requires deck space for treatment tanks and pumps. Water power fluid can be used. Power oil a fire and safety problem.

Good. Produced water or seawater may be used as a power fluid with wellsite type system or power fluid separation before production treating system.

Excellent and is the most common method if adequate injection gas available.

Poor in wells needing sand control. Use of standing valves risky. Heading causes operating problems.

Excellent for correct application.

Paraffin handling capacity

Fair to good. Hot water/oil treating and/or use of scrapers possible but they increase operating problems and costs.

Fair. Tubing may require treatment. Rod scrapers not used. Possible to unseat pump and circulate hot fluids.

Fair to good. Hot water/oil treatments, mechanical cutting, batch inhibition possible.

Good to excellent. Circulate heat to downhole pump to minimise build-up. Mechanical cutting and inhibition possible. Soluble plugs available. Free pumps can be surfaced on a schedule.

Same as piston pump.

Good mechanical cutting sometimes required. Injection gas may aggravate existing problem.

Same as continuous flow gas lift.

Excellent as it cuts paraffin and removes small deposits.

Table 10.P 10 .P - Artificial Artificial Lift Considerations Considerations (Pg1)

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Rod Pumping

Screw Pumping

Slim-hole completions (27/8ins production casing string)

Feasible for low rates <100stb/d and low GOR <250. Typically are used with 1.5ins nominal tubing.

Feasible if low rates, low GORs and shallow depths but no known installations.

Solids/sand handling ability

Poor to fair for low viscosity <10cP production. Improved performance for high viscosity >200cP cases. May be able to handle up to 0.1% sand with special pumps.

Temperature limitation

ESP

0

Hydraulic Piston Pumping

Hydraulic Jet Pumping

Continuous Gas Lift

Intermittent Gas Lift

Plunger Lift

No known installations.

Possible but may have high friction losses or gas problems. Suitable for low rates and low GLRs.

Same as piston pump.

Feasible but can be troublesome and inefficient.

Same as continuous flow.

Good. Similar to casing lift but must have adequate formation gas.

Excellent up to 50% sand with high viscosity >200cP crude. Decreases to <10% sand for water producers.

Poor. Requires <200ppm solids. Improved wear resistant materials available at premium cost.

Poor. Requires <10ppm solids power fluid for good run life. Also produced fluids must have low solids <200ppm of 15µm particles for reasonable life. Use fresh water injection for salt build-up formations.

Fair to good. Jet pumps are operating with 3% sand in produced fluids. Power fluid to  jet pump can tolerate 200ppm of 25µm particle size. Fresh water treatment for salt formations.

Excellent. Limit is inflow and surface problems. Typical limit is 0.1% sand for inflow and outflow problems.

Fair but standing valve may cause problems. Same as continuous flow.

Sand can stick plunger, however it wipes tubing clean.

Excellent and currently used in thermal operations. 550oF.

Fair but limited by stator elastomer. At present normally below o 250 F.

Limited to about o <250 F for standard and <325oF with special motors and cables.

Excellent. Standard materials up to 300oF+ and to 500oF+ feasible with special materials.

Excellent and possible to o operate to 500 F with special materials.

Excellent. Typically a maximum of about 350 oF. Need to know temperatures to design bellows charged valves.

Same as continuous flow.

Excellent.

High viscosity fluid handling capability

Good for <200cP fluids and low rates 400stb/d. Rod fall problems for high rates. Higher rates may required dilutent to lower viscosity.

Excellent for high viscosity fluids with no stator/rotor problems.

Fair, limited to about 200cP. Increases HP and reduces head. Potential solution is to use ‘core flow’ with 20% water.

Good in >8 API production with <500cP possible. Power fluid can be used to dilute low gravity production.

Good to excellent. Production with up to 800cP possible. Power oil of oil >24 o API and ,50cP viscosity or water power fluid reduces friction losses.

Fair. Few problems for >16 o API. or below 20cP viscosity. Excellent for high water cut lift even with high viscosity oil.

Same as continuous flow

Normally not applicable.

High volume lift capacity

Fair but restricted to shallow depths using large plungers . max. rate about 4,000stb/d from 1,000ft and 1,000stb/d from 5,000ft.

Poor. Restricted to relatively small rates. Possibly 2,000stb/d from 2,000ft and 200stb/d from 5,000ft.

Excellent. limited by needed HP and can be restricted by casing size. In 5.5ins casing can produce 4,000stb/d from 4,000ft with 240 HP. Tandem motors can be used but will increase costs.

Good. Limited by tubular and HP. Typically 3,000stb/d from 4,000ft and 1,000stb/d from 10,000ft with 3,500psi system.

Excellent. Up to 15,000stb/d with adequate flowing bottomhole pressure, tubular size and HP.

Excellent. Restricted by tubing size and injection gas rate and depth. Depending on reservoir pressure and PI with 4ins nominal tubing, rates of 5,000stb/d from 10,000ft feasible with 1,440psi injection gas and GLR of 1,000.

Poor. Limited by cycle volume and number of possible injection cycles. Typically about 200stb/d from 10,000ft with <250psi pump intake pressure.

Poor. Limited by number of cycles. Possibly 200stb/d from 10,000ft.

Low volume lift capabilities

Excellent. Most commonly used method for wells producing <100stb/d.

Excellent for <100stb/d shallow wells that do not pump-off.

Generally poor. Lower efficiency and high operating costs for <400stb/d.

Fair. Not as good as rod pumping. Typically 100 to 300stb/d from 4,000 to 10,000ft, >75stb/d from 12,000ft possible.

Fair, >200stb/d from 4,000ft.

Fair. Limited by heading and slippage. Avoid unstable flow range. Typically lower limit is 200stb/d for 2ins tubing without heading, 400stb/d for 2.5ins and 700stb/d for 3.5ins tubing.

Good. Limited by efficiency and economic limit. Typically 0.5 to 4stb/cycle with up to 48 cycles/d

Excellent for low flow rates of 1 to 2stb/d with high GLRs.

o

Table 10.Q 10. Q - Artificial Artificial Lift Considerations (Pg2)

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11.

USE OF UNDERBALANCE COMPLETION FLUIDS

11.1.

POLICY

The purpose of this section is to provide the basic criteria when ‘non-kill weight packer fluids’ can be used in completion design. The use of non-kill weight packer fluid has been thoroughly evaluated and is permitted for the wells which have pressure gradients above 1.30kg/Lt/10m, i.e. high pressure and high temperature (HP/HT) wells. This policy does not refer to gradients below 1.30kg/Lt/10m where it is still considered good practice to use overbalance completion fluids. 11.2.

BARRIER PRINCIPLES

Eni-Agip Division and Affiliates has determined that a packer fluid, regardless of the density, cannot be considered as a barrier. The main reasons are:

•

•

•

11.3.

The integrity of the annulus, with regard to double barrier protection is mechanically obtained by means of the wellhead, the tubulars (tubing and casing) and packer system and, therefore, does not require the presence of an overbalance fluid. A hydrostatic overbalance fluid can only be considered a barrier on a long term basis if it is fully maintained, however tubing leaks and deterioration of the fluid cannot be guaranteed. This being the case, it should not be classified as a barrier. Over and above this, some completion types such as High Rate liners using a liner PBR may be some considerable distance from the formation, therefore is not a practical barrier.

APPLICATION

The use of non-kill weight packer fluid will be considered in the following situations:

• • •

When a brine with a gradient lower than the formation gradient has already been used as completion fluid, i.e. through tubing perforation after packer setting. When it is necessary to replace a completion fluid containing solids in suspension, i.e. high density oil mud. The re-use of the completion fluid is envisaged when it is opportune or cost effective.

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RISK ASSESSMENT ASSESSMENT

11.4.1. Well Testing

For exploration wells, prior to commencing a well test using non-kill weight packer fluid, a risk analysis evaluation (HAZOP) must be carried out by the District Drilling & Completion Engineering Department, in order to identify and evaluate the operative risks associated with downhole equipment functionality. 11.4.2. Completions

Similar to above, a risk assessment should be carried out to ensure, if an underbalance completion fluid is to be used, that the completion design will keep the formation pressure off the production casing. However, as contingency against a tubing/packer envelope leak, the casing design must be able to withstand full well pressure in conjunction with the completion fluid hydrostatic pressure at respective depth. The worst possible case being immediately immediately above the packer.

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APPEN PPENDI DIX X A - RE REP PORT ORT FOR FORMS MS To enable the contents of this completion manual and other operating procedures manuals to be improved, it is essential that ENI - Agip Division and Affiliates obtain feed-back from the field. To this end a feed-back reporting system is in use which satisfies this requirement. Feed-back reports for drilling, completion, workover and well testing operations are available and must be filled in and returned to head office for distribution to the relevant responsible departments as soon as possible as per instructions. The forms relevant to completion operations are:

• • • • • • • • • •

ARPO 01

Initial Activity Report

ARPO 02

Daily Report

ARPO 06

Was Waste Disposal Management Report

ARPO 07

Perf orating Report

ARPO 08

Gravel Pack Report

ARPO ARPO 09

Matr atrix Sti Stim mulat ulatiion/H on/Hyd ydra raul uliic fra fract ctur uriing Repor eportt

ARPO 11

W ireline Report

ARP ARPO 12

Pre Pressure/T e/Temperatur ture Sur Survey Report

ARPO 13

W ell Problem Report

ARPO 20

W el ell Situation Report

Behind each report form are instructions on how to fill in the forms. As the first section is generic to all the forms it is only shown in ARPO 01 instructions.

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INITIA TIAL AC ACTIVI TIVITY TY REPOR EPORT T (A (ARPO 01 01))

District Affiliate Affiliate ompany DATE:

INITIAL ACTIVITY REP RT

WELL NAME FIELD NAME

ARPO 01

Permit/Concession N°

Cost center

Well Code

General Data On shore

Depth Above S.L .

Off shore

Joint venture

Ground Level[m]

AGIP:

Latitude:

Water Depth [m]

Longitude

Rotary Table Elev.[m]

Reference

First Flange[m]

Rig Name

Top housing [m]

Contractor

Ref. Rig RKB - 1st Flange

%

%

Program TD (Measured)

[m] [m]

Rig Pump

Depth [m]

Manufacturer

Distance [m]

Length [m]

Type

Direction [°]

Width [m]:

Liner avaible [in]

Offset FROM the proposed location

% %

Program TD (Vertical)

Cellar Pit

Rig Heading [°] [°]

% %

Type of Operation

Reference Rig

Rig Type

Major Contractors Type of Service

Company

Contract N°

Type of Service

Company

Contract N°

Mud Logging D. & C. Fluids Cementation Waste treatment Operating Time

Jack-up leg Penetration

Supply Vessel for Positioning

Moving

[gg:hh]

Leg

Air gap

Penetration

Positioning

[hh:min]

N°

[m]

[m]

Anchorage

[hh:min]

Rig-up

[hh:min]

Delay

[hh:min]

Lost-time Accidents

[hh:min]

N°

Name

Horse Power

Bollard pull [t]

Rig Anchorage Anchor Bow N°

Angle

Mooring Line Weight

Type & Manufacturer

[t]

Piggy Back

Length Cable

Chain

[m]

[m]

Weight N°

[t]

Mooring Line Chain

Tension Op O perative

Cable

Length

Ø

Length

Ø

[m]

[mm]

[m]

[mm]

Total

[Tested]

Tension

Time

[t]

[t]

[hh:min]

1 2 3 4 5 6 7 8 9 10 11 12 Note:

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Supervisor

Superintendent

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DAILY REPORT (ARPO 02)

DAILY REPORT

WELL NAME

Drilling

FIELD NAME

District/Affiliate Company

A RP RPO 02 02

DATE:

C os os t ce nt nte r

Rig Name

RT El evati on

[m]

Type of Rig

Ground Lelel / Water Depth

[m]

Contractor

RT - 1 flange / Top Housing

st

L as as t ca si si ng ng

Ø

[m]

T.V.D. (24:00)

[m ]

Top [m]

Diverter

Total Dril led

[m ]

Bottom [m]

A nnul ar

Rotating Hrs

[hh:mm ] [m / h]

Top of Cmt [m]

BOP

w.p. w.p. [psi] [psi]

of

M.D. M.D. (24:00 (24:00))

Ø nom.[in]

Type

Report N° Perm Permit it / Con Conce cess ssio ion n N° N°

S tack

Well

Ne xt xt Ca si si ng ng

[m] [m]

W el l Code

Annul ar

R.O.P.

Last Survey [°]

at m

Upper Rams

Progressive Rot. hrs

[hh:mm ]

LOT - IFT [kg/l]

at m

Middl e Ram s

B ack reaming Hrs

[hh:mm ]

Reduce Pump Strockes Pressure Pump N°

1

2

Personnel

Middle Rams 3

Middle Rams

Injured

Agip

Agip

Liner [in]

Lower Rams

R ig

Rig

Strokes Press. [psi ]

Last Test

Others Total

Other Total

Lithology Shows From From (hr (hr)

To (hr) (hr) Op. Op. Code Code OPERATION DESCRIPTION

Operation at 07:00 Mud type Density Viscosity P.V. Y.P. Gel 10" /10' Water Loss HP/HT Press. Temp. C l-lSalt pH/ES MBT S ol ol id id Oil/water Ratio. Sand pm/pom pf mf Daily Losses Progr. Losses

[kg/l] [s/l ] [cP] 2 [g/100cm ] / [cc/30"] [cc/30"] [kg/cm2] [°C] [g /l/l ] [g/l ] [kg/ [kg/m m] [% ] [%]

Bit Data Manuf. Type Serial No. IADC Diam . Nozzle/TFA From [m] To [m] D riri llll ed ed [ m] m] Rot. Hrs. R.P.M. W.O.B.[t] Fl ow ow Rat e Pressure A nn. vel. Jet vel. HHP Bit HSI 3 I [m ] [m ] B

N°

Run N°

N°

Run N°

Bottom Hole Assembly N°__________  Rot. hours Ø Description Pa rt rt . L P ro ro gr gr .L .L P ar art ia ial Pr og og r. r.

Stock

Total Cost O G

D O

L R

I B

O G

D O

L R

Daily Progr.

Quantity

UM

Supervisor:

Supply vessel

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WASTE WASTE DISPO DISPOSA SAL L MANAGEMEN GEMENT T REPO REPORT RT (ARP (ARPO O 06) 06)

WASTE DISPOSAL

WELL NAME

Management Report

FIELD NAME

District/Affiliate Company

ARPOARPO-06 06 Cost Cost center center

DATE:

Report N°

Depth (m)

Mud Type

From [ m]

Interv al Drilled (m)

To [m]

Drilled Volume [m ]

Density (k g/l)

Phase size [in]

Cumulative volume [m ]

3

Cl- concentration (g/l ) 3

3

Usage

3

Phase /Period [m ]

Water consumption

Fresh water

Recycled

Cumulat ive [m ] Total

Fresh water

Recyc led

Tot al

Mixing Mud Others Total 3

3

Fresh water [m ]

Readings / Truck 3

Mud Volume [m ]

Phase

Cumulative

Recycled [m ] Service

Mixed

Company

Contract N°

Mud Company

Lost

Waste Disposal

Dumped

Transportation

Transported IN

Waste Disposal i

Period

Oil base cuttings

[t]

Dried Water base cuttings

[t]

Dried oil base cuttings

[t]

Water base mud

[t]

Oil base mud t ransported ransported IN

[t]

Oil base mud transported OUT

[t]

Drill potable water

[t]

Dehidrated water base mud

[t]

Dehidrated oil base mud

[t]

Sewage water

[t]

Transported Brine

[t]

Cumulative

Remarks

Remarks

Supervisor

Superintendent

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PER ERF FORA ORATIN TING REP REPOR ORT T (A (ARPO 07 07)

PERFORATING

WELL NAME FIELD NAME

District/Affiliate Company A RP RP OO-0 7

DATE: Well location Onshore

Co st st c en ent er er

Formation name:

Pool:

Lithology

Offshore [m]

Total Depth

st

Drilling Rig RKB - 1 Flange

M.D.

Well Type

Final Workover Report [date]

st

Workover Rig RKB - 1 Flange

Vertical

T.V .D.

De vi via te te d

Max . i nc nc lilin at at iio on

Horizontal

at Size [Ø]

Well

Final Completion Report [date]

Rotary Table Measurement [m]

Situation

Reference Logs:

[ °]

W or ork ov ov er er Ri g RK B - S ea ea Le ve vel

[ m]

Workov er Rig RKB - Sea Bottom

Steel

Thickness

Grade

[lb/ft]

Measured Depth Top [m]

Bottom [m]

Recorded on: Vertical Depth Top [m]

Bottom [m]

Cement Top M.D. [m]

T.V.D. [m]

Liner Casing Casing Tubing

Service Company

Packer Tubing shoe Perforation System Wireline

Overbalance

Com pletion fluid

Density

[kg/l]

TCP

Underbalance

Fluid in front of Perforation

Density

[kg/l]

Thru Tubing

Differential Pressure [kg/cm ]

Data

2

Gun

Gun

Gun

Charge

Type

Specific.

Ø

Type

Fluid Losses after Perforation S.P.F

Measured Depth Top [m]

Bottom [m]

[m3] Vertical Depth Top [m]

Bottom [m]

Note:

Supervisor

Superintendent

Pool

Remarks

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GRAVEL PA PACK REP REPOR ORT T (A (ARPO 0 08 8)

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MATRI MA TRIX X STIM STIMUL ULA ATION/H TION/HYD YDRA RAUL ULIC IC FRACTU FRACTURE RE REPORT REPORT (APRO (APRO 09)

MATRIX STIMULATION HYDRAULIC FRACTURING

WELL NAME FIELD NAME

District/Affiliate Company ARPO ARPO - 09 09

DATE: Well Location

Cost Cost ce center nter

General Data

Interval to be Treated

Onshore

M.D. [m]

Open hol e

Tot. net perf.:

Offshore

T.V.D. [m]

Perfor. interval

Formation name:

Well Type Vertical

O p e n h ol e Ø Prod. casing / liner Ø

Sl otted l iner From [m]

Pool :

Devi ated Horizontal

Shoe M.D. [m] Top liner [m ]

To [m ]

Lithol ogy:

Treatment Type M atrix sti mulation

Reservoir Parameters

Treatment Data

Completion Data

Reservoir flui d

Service Com pany

Densi ty [Kg/l] 2 Gradient [Kg/cm  /10 m.]

HHP avai ble

Type

Solvent

Initial Shut-i n pressure [psi ]

Wellhead type

Other

Fracturing gradient [calcul ated]

Annul us pressure [psi]

Packer type

Fracturing gradient [tested]

Pressure test [psi ]

Packer flui d

Aci d

Hydraul ic Fracturing Foam

Porosity %

Water base

SBHT [°C] 2 SBHP [kg/cm ]

Oil base

Bottom hole gauge [Y / N]

Max. i njecti on rate [bpm]

Densi ty

at m

Max. i njecti on pressure [psi ]

Fluid in well at operation beginning

at m

Pumping ti me [min]

Other

Pumping ti me [min]

Acid Fracturing

String O.D. [in]

Equipment

Main Frac Treatment

String capacity [l ]

Acid

Proppant type:

Coiled Tubing [Y / N]

Gelled acid

API Mesh Si ze

Ø

Acid + G el

Am ount of Propant [t] 3 Total Frac Fluid Vol. [m ]

Stimulation vessel / Other equi pment

Other

Packer - Top perforation Volum e [l]

Operation Description Fluid Ref.

Fluid Schedule Fluid Com positi on

Fl uid T ype

Density [kg/l]

1 2 3 4 5 6 7 8 9 10 Pumping Parameter N° Fluid Ref.

   d   e    t   a    l   u   c   r    i    C

Starting

Pumpi ng

Ti me

Rate [bbl/1']

Volume 3

[m ]

Progr.

Progr.Vol .

Proppant

Initial

Fi n a l

Injecti on

Casing

V olume

Entering in Formation

Concentr.

Press.

Press.

I n de x

P ress.

[lb/gal ]

[psi]

[psi]

[bbl/day/psi]

[psi]

3

[m ]

Notes / Remarks: Supervisor

Superintendent

Notes

xe

oume m

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WIRELI ELINE REPOR EPORT T (ARPO 11)

WIRE LINE REPORT

WELL NAME FIELD NAME

District/Affiliate Company

ARPO ARPO - 11 11

DATE:

SINGLE COMPLETION

Cost Cost cen cente terr

SHORT STRING

SELECTIVE

DU AL COMPLETION

Well Code

LONG STRING General Data

RKB Elevation @ m .

Flanges

Base Flange

Tbg Spool

Top Flange Ø

Psi

Tubing Size OD

W eight [lb/ft ]

@ m.

Flowing Flange Ø

Psi

Tubing Size OD

W eight [lb/ft ]

@ m.

Kill Line Flange Ø

Psi

@ m. @ m.

BPV Type

Ø

Tubing Shoe Ø Packer data

@ m. Minim um I.D. String Previous Bottom Hole

Wellhead Pressure Check

[Kg/cm2]

THP @ m.

Request Operation

[Kg/cm 2]

CHP

2

Annulus

/

P

Annulus

/

P

[Kg/cm ] [Kg/ [Kg/cm cm ]

Annulus

/

P

[Kg/cm 2]

POOL

Perf orated Zones

Open Hole

From [m ]

To [m]

Note

Operation Description

Situation After the Job NO TOO LS IN HOLE TSV Note

SCSSV BPV

PLUG

Actual Bottom Hole: O THER TOOLS

Max Size Run in Hole Ø Supervisor Superintendent

@m

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PRESS PR ESSU URE RE/TE /TEM MPERA PERATURE TURE SU SURV RVEY EY RE REPOR PORT T (ARP (ARPO O 12) 12)

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WELL PR PROBL OBLEM REPOR PORT (A (ARPO 1 13 3)

WELL PROBLEM REPORT

District/Affiliate Company Company

ARPO ARPO -13 -13

DATE: Problem Code Well

Ø

Situation

WELL NAME Cost Cost cen cente terr Start date

Bottom [m]

End date

Measured Depth Top [m]

FIELD NAME

Top [m]

Vertical Depth

Bottom [m]

Top [m]

KOP

Bottom [m]

Open hole

Mud in hole

[m]

Max inclination [°]

Type

@m

Last casing

Dens.[kg/l]:

DROP OFF [m]

Well problem Description

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Supervisor

Supervisor

Supervisor

Remarks at District level:

Superintendent Lost Time Remarks at HQ level

OF 295

REVISION STAP-P-1-M-7100

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hh:mm Loss value [in currency] Pag. Of

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WELL ELL SITU SITUA ATION TION REPOR EPORT T (A (ARPO 20 20))

WELL SITUATION

FIELD NAME

COMPLETION TALLY

WELL NAME

District/Affiliate Company

ARPO 20 / E

DATE:

SINGLE COMPLETION Joint n°

m

Progr. m

DUAL COMPLETION Note

Joint

Cost center

SHORT STRING

m

Progr.

n°

Note

m

Joint

LONG STRING m

n°

Supervisor

Remarks:

Superintendent pag. :

of:

Progr. m

Note

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APPEN AP PENDIX DIX B - NOMENCL NOMENCLAT ATURE URE FOR TUBING TUBING CAL CALCUL CULAT ATIONS IONS Ai Ao Ap As D d Dpb E F Fa * Fa Fa tp * Fa tp Ff * Ff I Ff II Ff Ff tp * Ff tp Fp Fso I L n

= = = = = = = = = = = = = = = = = = = = = = = =

Pi /pi Po /po R r t Tfinal Tinitial w ws wfi wfo

= = = = = = = = = = = = = = = = = = = = =

α γ fifi γ fofo ∆Fa ∆Ff ∆L ∆L1 ∆L2 ∆L3 ∆L4

Area inside tubing Area outside tubing Packer-bore area Resistan tant tub tubing area (Ao - Ai) External diameter of tubing Internal diameter of tubing Packer-bore di diameter 7 Young’s module (3 ⋅10 psi for steel) Generic force applied to the tubing end Piston ton for force at the the packer depth pth Pist Piston on force force abov above e the the pack packer er with with anch anchor ored ed tubi tubing ng Pist Piston on for force at well ell head head cond condiition tions s Pisto Piston n forc force e at at w wel elll head head condi conditi tion ons s wit with h anc ancho hore red d tub tubin ing g Fictitious f orce Fict Fictit itio ious us for force ce abov above e the the pack packer er with with anc ancho hore red d tubi tubing ng Fict Fictit itio ious us forc force e due due to the the effe effect ct of int inter erna nall pre press ssur ure e Fict Fictit itio ious us forc force e due due to the the effe effect ct of ext exter erna nall pre press ssur ure e Fict Fictiitiou tious s for force ce at well ell hea head d con condi diti tion ons s Ficti Fictiti tiou ous s forc force e at at wel welll hea head d con condi diti tion ons s wit with h anch anchor ored ed tubin tubing g Tubing-packer force Slack-off f orce Moment of inertia of the resistant tubing section Tubing length Distance between the lower end of the tubing and the n e u t r al point Pres Pressu sure re insi inside de the the tub tubin ing g at at pack packer er dept depth h / wel welll hea head d Pres Pressu sure re outs outsid ide e the the tubi tubing ng at pac packe kerr dep depth th / wel welll hea head d Ratio between the external and internal diameters of the tubing Tubing-casing ra radial distance (Douter casing -D)/2 Tubing wall thickness Final temperature of tu tubing Initial tte emperature of of tu tubing Linear weight of the tubing immersed in fluid Linear ear weight of the the tub tubing in air Line Linear ar weigh eightt of of flui fluid d ins insiide the the tub tubiing Line Linear ar weigh eightt of of flui fluid d out outs side ide the the tubi tubing ng -6 Coeffi oeffici cien entt of ther therm mal expa expans nsiion (6.9 6.9⋅ 10 in/in/° in/in/ °F for steel) s teel) Spec Speciific fic gr gravi avity of flfluid uid ins insiide the the tub tubin ing g Spec Speciific fic gr gravi avity of flfluid uid out outsi side de the the tub tubin ing g Variation in in th the pi piston fo force Variatio tion in in th the fifictitious ous for force Generic variation in the tubing length Vari Variat atiion in lengt ength h due due to Hooke ooke’s ’s Law Law Variatio tion in in len leng gth due to to bu buckling Vari Variat atiion in lengt ength h due due to bal balloon looniing Vari Variat atiion in len lengt gth h due due to ther therm mal effe effect cts s

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= = = = = = = = = = = = = = = =

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∆Lp ∆Lf ∆lso ∆ltot ∆Pi ∆pim ∆pom ∆TM  ν σa σb σeq σi σo σsn

288

0

Tota Totall var varia iati tion on in leng length th prev preven ente ted d by by the the pack packer er Vari Variat atio ion n in in len lengt gth h gen gener erat ated ed by fict fictit itio ious us force force Vari Variat atio ion n in in len lengt gth h gen gener erat ated ed by slac slackk-off off forc force e Tota Totall var variiati ation in len lengt gth h of of the the tub tubiing (= - ∆Lp) Vari Variat atiion in pre press ssur ure e ins insid ide e the the tubi tubing ng Aver Averag age e var varia iati tion on in pres pressu sure re insi inside de the the tub tubin ing g Aver Averag age e var varia iati tion on in pres pressu sure re outs outsid ide e the the tubi tubing ng Aver Averag age e var variiatio ation n in in tub tubiing temp temper erat atur ure e Poi Poisson sson’’s coef coeffi fici cien entt (0.3 (0.3 for for steel teel)) Axial str stre ess in in the the tubin bing se section Axia Axiall str stres ess s in in the the tubi tubing ng sect sectio ion n due due to buck buckli ling ng Equivalent axial stress Equi Equiva vale lent nt axi axial al stre stress ss on the the inn inner er wall wall of the the tubi tubing ng Equi Equiva vale lent nt axi axial al stre stress ss on the the out outer er wall wall of the the tubi tubing ng Material yi yield ax axial st stress

σsn

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APPEN PPENDI DIX X C - AB ABBR BREV EVIA IAT TIONS IONS API BHA BHP BHT BOP BPD BPM BPV BSW BUR C/L CBL CCL CET CGR CRA C/T DC DE DHSV D&CM DP DST E/L ECD ECP EMW ESD ESP ETA FBHP FBHT FTHP FTHT GLR GOC GOR GP GPM GPS GR HAZOP HP/HT IADC ID

289

American Petroleum Institute Bottom Hole Assembly Bottom Hole Pressure Bottom hole temperature Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Base Sediment & Water Build Up Rate Control Line Cement Bond Log Casing Collar Locator Cement Evaluation Tool Condensate Gas Ratio Corrosion Resistant Alloy Coiled Tubing Drill Collar Diatomaceous Earth Down Hole Safety Valve Drilling & Completion Manager Drill Pipe Drill Stem Test Electric Line Equivalent Circulation Density External Casing Packer Equivalent Mud Weight Electric Shut-Down System Electrical Submersible Pump Expected Arrival Time Flowing Bottom Hole Pressure Flowing Bottom Hole Temperature Flowing Tubing Head Pressure Flowing Tubing Head Temperature Gas Liquid Ratio Gas Oil Contact Gas Oil Ratio Gravel Pack Gallon (US) per Minute Global Positioning System Gamma Ray Hazard and Operability High Pressure - High Temperature International Drilling Contractor Inside Diameter

0

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IPR JAM KOP LAT LCM LMRP LOT LWD MAASP MD MLH MLS MMS MMS MODU MPI MSL MSS MWD NACE NDT NSG NTU OBM OD OIM ORP OWC P&A PBR PDC PDM PGB PI PLT POB PPB ppg ppm PVT Q Q/AQ RFT RKB ROE ROP ROU ROV

290

Inflow Performance Relationship Joint Make-up Torque Analyser Kick Off Point Lowest Astronomical Tide Lost Circulation Materials Low Marine Riser Package Leak Off Test Log While Drilling Max Allowable Annular Surface Pressure Measured Depth Mud Line Hanger Mud Line Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Magnetic Particle Inspection Mean Sea Level Magnetic Single Shot Measurement While Drilling National Association of Corrosion Engineers Non Destructive Test North Seeking Gyro Nephelometric Turbidity Unit Oil Base Mud Outside Diameter Offshore Installation Manager Origin Reference Point Oil Water Contact Plugged & Abandoned Polished Bore Receptacle Polycrystalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Production Logging Tool Personnel On Board Pounds per Barrel Pounds per Gallon Part Per Million Million Pressure Volume Temperature Flow Rate Quality Assurance, Quality Control Repeat Formation Test Rotary Kelly Bushing Radius of Exposure Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle

0

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RPM RT S/N SAFE SBHP SBHT SCC SCSSV SDE SF SG SICP SIDPP SPM SSC SSD SSSV STHP STHT TCP TD TOC TOL TRSV TVD UHF UH F VBR VDL VHF VSP W/L WBM WC WHP WHSIP WOB WOC WOW WP YP

291

Revolutions Per Minute Rotary Table Serial Number Slapper Activated Firing Equipment Static Bottom Hole Pressure Static Bottom Hole Temperature Stress Corrosion Cracking Surface Controlled Subsurface Safety Valve Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Shut-in Drill Pipe Pressure Stroke per Minute Sulfide Stress Cracking Sliding Sleeve Door Valve Sub Surface Safety Valve Static Tubing Head Pressure Static Tubing Head Temperature Tubing Conveyed Perforations Total Depth Top of Cement Top of Liner Tubing Retrievable Safety Valve True Vertical Depth Ultra High Frequency Variable Bore Rams (BOP) Variable Density Log Very High Frequency Velocity Seismic Profile Wire Line Water Base Mud Water Cut Well Head Pressure Well Head Shut-in Pressure Weight On Bit Wait On Cement Wait On Weather Working Pressure Yield Point

0

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APPEN PPENDI DIX X D - BI BIBL BLIO IOGR GRA APHY Document:

STAP Number

Drilling Design Manual

STAP P-1-M-6100

Connection Procedures Manuals.

STAP M-1-M 5006

Other References:

Ansari, A ‘ A Comprehensive Mechanistic Model For Multiphase Flow In Wells’, MS Thesis, The University Of Tulsa (1988) API BUL 5C3 Sixth Edition: ‘Formulas and Calculations for Casing Tubing Drill Pipe, and Line Pipe Properties’, October 1, 1994. API RP 14E ‘Recommended Practices For Design And Installation Of Offshore Production rd Platform Piping Systems, 3 edition (Dec 1981) API RP 14E Fourth Edition: ‘Recommended Practice for Design and Installation of Offshore Production Platform Piping System’, April 15, 1984. Arthur Lubinsky: ‘Helical Buckling of Tubing Sealed in Packers’, 36th Annual Fall Meeting of SPE, Dallas, October 8-11, 1961. Aziz, K, Covier, GW and Fogarasi, M : ‘ Pressure drop in wells producing oil and gas’ (July Sept 1972), 38-48 Beggs, H D and Brill, J P : ‘ A study of two-phase flow in inclined pipes’ (May 1973), 607617 Blount, E M, Jones, L G and Glaze, O H : ‘Use of short term multirate flow tests to predict performance of wells having turbulence’ (1976) Brown, K E : The Technology Of Artificial Lift Methods, Vols 1 And 4, Ponwell Publishing Company, Tulsa, OK, 1977 Bruist, E HY : ‘ Better performance of Gulf Coast wells’( 1974) D. J. Hammerlind: ‘Basic Fluid and Pressure Forces on Oilwell Tubulars’, 53th annual Fall Technical Conference and Exhibition, Houston, October 1-4, 1978. D. J. Hammerlind: ‘Movement, Forces and Stresses Associated With Combination Tubing Strings Sealed in Packers’, Journal of Petroleum Technology, February, 1977. Duns, H JR and Ros, N C J : ‘ Vertical flow of gas and liquid mixtures in wells’ (1963), 451 Earlougher, R C JR and Kersch K M : ‘ Analysis of short-time transient test data by typecurve matching’ (July 1974) 793 Eickmeier, J R : ‘ How To Accurately Predict Future Well Productivities’ ( May 1968) 99-106 Fetkovich, M J : ‘ The Isochronal Testing Oil Wells’ (1973) Forcheimer, P ;P ‘ Wasserbewegung Durch Boden’ (1901) 45, 1781-1788 (in german) Gilbert, W.E: ‘Flowing and Gas-Lift Well Performance’ API Drill and Prod Pract (1954), 126 Golan, M and Whiston, C H: Well Performance, International Human Resource Development Corporation, Boston, NY (1986)

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Gray, H E : ‘ Vertical Flow Correlation-Gas Wells’ API Man 14BM; API 14B, SSCSSV Sizing Computer Program, 38-40 H. D. Beggs: ‘Production Optimisation Using NODAL Analysis’, OGCI, Tulsa, 1991. Hagedoorn, A R and Brown, K E: ‘ Experimental study of pressure gradients occurring during continuous two-phase flow in small diameter vertical conduits’ ( April 1965) 475-484 Hagedorn and Brown (1967) Horner, D R : ‘ Pressure P ressure build up in wells’ (1951) Hurst, W : ‘ Establishment of skin effect and its impediment to fluid flow into a wellbore’ (Oct 1953) King, G E, Anderson, A R and Bingham, M D ‘ A field study of underbalance pressure necessary to obtain clean perforations using tubing-conveyed perforating’ ( June 1986) 662 Lea, J F JR and Tighe, R E : ‘ Gas Well Operations With Liquid Production’ ( 1983) Milner, E E and Warren D A JR : ‘ Drill stem test analysis utilising McKinley system of after flow dominated pressure build up’ (Oct. 1972) Orkiszewski, J : ‘ Predicting Two-Phase Pressure Drops In Vertical Pipes’ (June 1967), 829838 Ramey, H J JR : ‘ Short-Time Well Test Data Interpretation In The Presence Of Skin Effect And Wellbore Storage, (Jan 1970) 97 Rawlins, E L and Schellhardt, M A : ‘ Back-Pressure Data On Natural Gas Wells And Their Application To Production Practices’ US Bureau Of Mines, (1936) Reinicke, K M, Remer, R J and Hueni, G : ‘ Comparison Of Measured And Predicted Pressure Drops In Tubing For High-Water-Cut Gas Wells’ (Aug 1987) 165-177 Saucier, R J : ‘ Gravel pack design consideration’ (Feb 1974) Standing, M B : ‘ Concerning The Calculation Of Inflow Performance Of Wells Producing From Solution Gas Drive Reservoirs’ (Sept 1971) 1141-1142 11 41-1142 Texas Railroad Commission Rule 36 Turner, R G, Hubard, M G and Duckler, A E : ‘ Analysis And Predictions Of Minimum Flow Rate For The Continuous Removal Of Liquid Liquid From Gas Wells’ (Nov 1969) Van Everdingen, F : ‘ The Skin Effect And Its Influence On The Productive Capacity Of A Well’ (Oct 1953) Van Poollen, H K : ‘ Radius-Of-Drainage And Stabilisation Time Equations’ (Sept 1964) Vol 62. No 37 Vogel, J V : ‘ Inflow Performance Relationships For Solution Gas Drive Wells’, (Jan 1968) 83-93

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APPEN AP PENDIX DIX E - TUBING TUBING MOVEMEN MOVEMENT/S T/STRE TRESS SS COMPU COMPUTER TER PROGRAM PROGRAMMES MES E . 1.

‘VERTUB TUBING’ PR PROGRAMME

The need to fast computing to carry out tubing movement/stress calculations led AGIP to produce the ‘Vertubing’ programme in 1989. This application was based on a previous version designed by a company named ‘Tubmov’ which was run on Hewlett Packard 41CV computers. The ‘Vertubing’ programme provided a calculation tool which significantly reduced times for engineers involved in string string calculations. The programme programme also enabled users to find an optimal solution by means of the iterative process using a number of approximations and producing results which were more reliable. The programme is supported by VAX/VMS computer systems and is currently available at Head Office and in the Districts on the Company computer network. The application carries out all functions for tubing control in vertical or deviated wells, with a string and a high number of packer’s as well (multiple zone completions) and takes into account the fact that packer setting can be mechanical or hydraulic. It is also possible to check stress tubing’s with varying diameters (tapered string) and to consider materials materials with anisotropic characteristics. It is not, however, possible to take into account the reduction in the performance of some CRA CRA type steels, caused by temperature increases. The programme does not incorporate a library or collection of data on commonly used tubing material, which would enable users to design the string starting from an existing material. The programme’s architecture defines a rigid sequence for data entry, which results in extremely accurate results. The application does not enable the user to independently assess dynamic situations such as with production or injection operations. It is necessary to calculate load losses during the relative operation and obtain the resulting fictitious hydrostatic gradient which then lets the user obtain the correct pressures for the various string sections. ‘Vertubing’ produces the results as numerical files, without any graphic display. The programme is generally considered to be reliable because the results of three years use have consistently matched actual well applications.

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‘WELLCAT’ PR PROGRAMME

Eni-Agip Division and Affiliates recently acquired Enertech’s (1994) ‘Wellcat’ programme which is an application integrating the most specialised software, ranging from drilling, to completion and other various well operations. The brief description below only describes the parts of the application concerning tubing. The need to use an in-house company company programme which was was more complex compared to ‘Vertubing’, is due to this application’s limitations in terms of obtaining the trend of temperatures the string is subject to during various well operations, and the inability to analyse dual completions. As ‘Vertubing’ had to be integrated with software in ENI-Agip Division and Affiliates expert system (Welcome) it seemed more appropriate to use a modern design programme such as ‘Wellcat’. The programme incorporates five modules. modules. The WT-Drill module lets the user evaluate the temperatures and pressures during drilling and the casing installation stages, while the resulting stresses the casing is subject to are calculated using the WS-Casing module. The WT-Circ and WT-Prod modules let the user evaluate the temperatures during standard production and circulation operations and the WS-Tube module lets the user calculate tubing movement and stress. ‘Wellcat’ can be used for single completions, selective completions with a maximum of five packers, dual completions with with a maximum of two packer’s packer’s and dual selective selective completions. The programme also assesses the installation of a hanger in the completion as well as hydraulic or mechanical packer setting. It is possible to evaluate the reduction in material rating due to temperature and any anistropy of materials. The calculation of load losses and the hydraulic conditions can be carried out using different correlations which are valid for two-stage flow (Beggs & Brill, Orkiszewski, Gray, Hagedorn & Brown, Duns & Ross), while the Govier-Aziz formula is used for single stage fluids. The most interesting feature of the programme is its capability to evaluate temperatures during and after well operations. During testing the results were compared to actual field data and a good match was obtained. It is also possible to calibrate the average coefficients for thermal exchange and specific heat, once the temperature profile and lithology of the formations are known. ‘Wellcat’ produces results in ASCII format, which can be read, printed or exported as graphic files. During processing it is also also possible to display display and print a simple simple drawing of the well and the completion. The ‘Wellcat’ programme was initially tested with the most typical cases (discussed in publications) and appropriate comparisons were made with data previously obtained using the ‘Vertubing’ programme with reasonable results. The programme is now used in the company for completion string design and at present available in PC, VAX Mainframe and UNIX versions.