Tubulars: Completion Equipment

Completion Equipment Tubulars API Specifications for Oilfield Tubulars The American Petroleum Institute (API) has defined certain standards for oilfield tubular goods, such as tubing and casing. The API has defined ten grades of steel: H40, J55, K55, C75, L80, N80, C90, C95, P105, and P110. The number indicates the API minimum yield strength in thousands of psi. The letters H, J, and N are primarily to minimize verbal confusion, while the others have an additional meaning: K — has higher ultimate strength than J C, L — "restricted yield strength" with tighter specifications P — high strength The behavior of tubular goods under stress conditions is a basic problem in strength of materials. The API has developed a set of standard formulas that are used throughout the oil industry to predict the minimum load-carrying capacity to be expected from a particular grade and weight of pipe (API Bulletin 5C3). Tables of casing and tubing strengths based on the formulas are also published by the API (Bulletin 5C2) and in various manufacturers' and service companies' handbooks. Remember that the API formulas are modified from time to time and it is important to make sure that the performance data used is taken from the most recent version. The major failure modes that we are concerned with are · burst · collapse · tension — failure of the coupling or pipe There is always some debate as to whether the API formulas are the best theoretical basis for computing a particular strength parameter (e.g., for burst, a modified Barlows equation is used instead of Lame). However, each company's assessment of the conservative nature or inadequacies of the API formulas is generally reflected in the design factor and design assumptions that they apply in using the API Strength Criteria.

Tubing Design Concept The uncertainties regarding actual loading conditions and the state of the tubing (e.g., corrosion, anomalies due to poor handling) considerably exceed our analytical capabilities to determine the resultant stresses. The tendency in the oil industry therefore has been not to be overly sophisticated in analyzing an extremely complex system, but rather to make designs on the basis of a set of idealized loading conditions that have proven adequate in the past, such as those presented in Table

1. It is important to remember that each company has its own philosophy, criteria, and design factors to consider. The balance of design assumptions versus actual conditions is depicted in Figure 1 (The balance of design assumptions versus actual conditions).

Figure 1

While this may lead to a tendency to overdesign, the relative cost of the convenience is generally fairly small. Extreme caution should therefore be used in making modifications to the idealized loading assumptions. For special, severe loading conditions (e.g., ultra deep >20,000 ft (6000 m), very high pressure >10,000 psi (70 MPa), very hot >300° F (150° C)), it is necessary to make a detailed computerassisted stress analysis.

Condition

Loading

Design Criteria

Typical Design Factor

Burst

Internal

Kill pressure on hydrocarbonfilled tubing

1.125

Collapse

Tension

External

Packer fluid and zero annulus pressure

Considerations

Check effects of compression

External

Casing head pressure= shutin tubing pressure

Internal

Tubing empty and depressured

Considerations

Check effects of tension

Running

Buoyant weight in completion fluid

1.125

Body: 1.333

Joint: 1.8* Tension and Compression

Operating

Cold stimulation and hot production conditions

Body: 1.125

Joint: 1.333

Total Stress

Considerations

Check effects of temperature and pressure changes

Triaxial

Max. stress

80% yield

*Assuming separate checks are not planned on shock and bending effects; otherwise use 1.5. Table 1: Typical criteria for tubing design on a flowing well In many field situations and preliminary estimates, to establish the weight and strength of the tubing it is sufficient simply to look at the tubing rating and to apply the corporate design factor. However, it must be recognized that loading conditions vary over the length of the tubing string, and to properly visualize this it is generally advantageous to carry out a graphical tubing string design. Graphical Tubing String Design

This is a convenient way of understanding loading conditions and presenting design results. The technique is presented in Example 2 (part 1) and illustrated in Figure 2 (Graphic tubing design estimated operating pressures),

Figure 2

Figure 3 (Graphic tubing design burst loads), and Figure 4 (Graphic tubing design

tubing selection).

Figure 3

Abbreviations are presented in the Nomenclature.

Figure 4

Example 2 (part 1) Graphical Tubing Design Planning Data

KBE:

3000 ft (915 m)

TD:

11,500 ft (3500 m)

Tbg:

2 7/8 in. OD (73 mm)

Closed-in bottomhole pressure:

5500 psi (38 MPa) estimated from mud weight

Formation breakdown

12,500 psi (86 MPa)

pressure: estimated from offset well Fracture propagation pressure:

9200 psi (63 MPa) estimated from offset well

Packer fluid:

inhibited oil (0.38 psi/ft)

Production:

expect sour gas (gas gravity = 0.80 — reservoir) (gas gravity = 0.70 — separator) J55 or L80 tubular to be used

Stimulation:

fracture expected (assume 20 barrels per minute); maximum allowable annulus pressure is 2000 psi (13,790 kPa)

THP Estimate

Depth of Hole

Gas Gravity

(ft)

(m)

0.60

0.65

0.70

0.80

1000

305

.979

.978

.976

.973

2000

610

.959

.956

.953

.946

3000

915

.939

.935

.930

.920

4000

1219

.920

.914

.907

.895

5000

1524

.901

.893

.885

.870

6000

1830

.883

.873

.854

.847

7000

2133

.864

.854

.844

.823

8000

2438

.847

.835

.823

.801

9000

2743

.829

.816

.804

.779

10,000

3048

.812

.798

.764

.758

11,000

3353

.795

.780

.766

.737

12,000

3660

.779

.763

.747

.717

13,000

3962

.763

.746

.729

.697

14,000

4267

.747

.729

.712

.678

15,000

4572

.732

.713

.695

.659

16,000

4876

.717

.697

.670

.641

17,000

5181

.702

.682

.652

.624

18,000

5486

.687

.656

.645

.607

19,000

5791

.673

.652

.631

.590

20,000

6097

.659

.637

.615

.574

Table 2: Ratio between surface pressure and bottomhole pressure in gas wells for a range of gas gravities At a gas gravity = 0.8, CITHP = 0.727

CIBHP = 3999 psi

At a gas gravity = 0.7, CITHP = 0.757

CIBHP = 4164 psi

For a kill situation: bottomhole injection pressure = CIBHP + 2000 psi = 5500 psi + 2000 psi = 7500 psi If gas gravity = 0.8, THIP = 0.727

BHIP = (0.727) (7500)

=5453 psi Assumed Fracture Conditions 1. Formation breakdown achieved with water 2. Fracture job carried out with water-base fluid Friction loss in 2 7/8 in. tubing at 20 BPM using water with friction reducer is 350 psi/1000 ft for 11,500 ft (Dowell Handbook) FPP = 9200 psi Friction = +4025 psi (350 Head = -5175psi (0.45

11.5) 11,500)

Frac THP= 8050 psi Prepare a depth pressure plot ( Figure 2 ) in the following manner: 1. Plot the closed-in bottomhole pressure (CIBHP). 2. Plot the formation breakdown pressure (FBP) and the fracture propagation pressure (FPP).

3. Plot the packer fluid gradient, fracture fluid gradient, and water gradient. 4. Estimate wet and dry gas gradients and plot these up from the closed-in bottomhole pressure. 5. Establish the closed-in tubing head pressure for normal production conditions (i.e., oil or, as in this case, wet gas) and for worst case design assumption (usually dry gas). 6. Establish maximum THP for which completion is to be designed, which normally will be kill or stimulation conditions (fluid gradient through FBP, FPP, or specified differential above CITHP). For Example 2, the graphical design should now look like Figure 2 . 7. Establish through inspection the greatest differential pressure at surface and downhole (usually stimulation conditions). Determine what steps can be taken to reduce loading (e.g., maintaining maximum allowable annulus pressure during stimulation). Plot adjusted annulus pressure line ( Figure 3 ). 8. Plot burst load line (BLL) as difference between most critical tubing and annulus pressures. The BLL is a function of the relative densities in the tubing and annulus. BLL will generally, but not always, decrease with depth ( Figure 3 ). 9. Plot critical collapse load conditions (CLL). Normally we assume that a slow leak has changed the CHP to CITHP and that tubing is empty and depressured. This can occur in gas wells if the tubing becomes plugged or a downhole safety valve is closed. Conditions can approach this situation in oil wells after a fracture treatment if operators commence kickoff before bleeding off annulus pressure. (In some cases this may be a more critical load ( Figure 4 ).) 10. Plot pressure test conditions (PT). This is often the most critical load to which a completion is subjected. Consider timing of the pressure test and density of fluids in the tubing and annulus at time of test. 11. Look up tubing performance data in API Bulletin 5C2. 12. Adjust API internal yield (burst) and collapse resistance specifications with design factor (see Figure 1 and API Bulletin 5C2). 13. List resulting tubing capabilities ( Figure 4 ). 14. Compare design loads with tubing capabilities and select tubing. In most cases the optimum tubing grade and weight will vary with depth. To minimize costs and/or tensional loads, such variations may be incorporated, although there will then be a constraint on pressuretesting capabilities. However, most operators prefer to use a common

weight and grade throughout the completion, if possible. This reduces the risk of installation and operating errors. When regulations permit, the designer may be able to compromise slightly on accommodating loading conditions deep in the hole, if the associated design assumption is extremely unrealistic (e.g., a completely empty tubing in a high productivity oil well). However, the designer must first check on how critical the actual biaxial (or triaxial) loading conditions are likely to be and make appropriate notes in the well file. With reference to Example 2, in Figure 4 the options include the following: 1. full string of 6.4 lb/ft L80 tubing 2. 0 to 6500 ft = 6.4 lb/ft J55 6500 to TD = 6.4 lb/ft L80 3. full string of 6.4 lb/ft J55 with modified collapse design criteria of 2000 psi as maximum CHP with an empty tubing Since 2000 psi is the maximum allowable annulus pressure during stimulation, option 3 may be an acceptable design. Since the differential cost of J55 and L80 is around $3 per ft, the potential saving of $34,500 between options 1 and 3 may justify further detailed engineering work. On the other hand, if the wellstream is expected to be extremely corrosive, the higher grade tubing may be selected in any case to provide a corrosion allowance. The key things to note from Figure 5 (Effect of buoyancy on axial load) are the most severe burst loadings occur at surface

Figure 5

the most severe burst and collapse loadings occur during pressure testing, well kill, and stimulation the most severe collapse loading occurs downhole additional annulus pressure can be used to reduce burst loading, provided the casing is strong enough the tubing-head pressure during kill operations (THIP) often approximates or exceeds the reservoir pressure (CIBHP) With relatively small tubing strings (<3.5 in. or 90 mm), the inherent burst and collapse strength is so high that some engineers do not bother with tubing design in wells with depths of less than 8000 ft (2500 m), unless overpressures are expected. Simplified Tensional Strength Design Although burst and collapse resistance may not be significant considerations in pumping wells, tensional strength is a critical design parameter for all wells. Coupling leakage and failure, which accounts for 80% of the problems in well tubulars, often

may be the result of inadequate tensional design rather than a burst or sealing problem. In this respect, it is particularly important to remember that test pressures impose substantial piston forces on the tubing (e.g., a 2000 psi (13.8 MPa) pressure test on a plug set inside 2 7/8-in. (73-mm) tubing will increase the tension on the hanger by (2000)( /4)(2.44l)2 = 9360 lb (42 kN). It is also important to recognize that, unlike other strength parameters, the API joint strength is based on a failure condition rather than the onset of plastic deformation. The failure condition is either an unzipping of the pin and box in the case of API threads, because of yielding (also called "jump-out"); or breakage of reduced cross section at the threads in the case of square threads. Finally, there are all sorts of additional tensional loads that we do not normally analyze in detail (e.g., shock loading and drag forces during running, bending stresses, buckling, cross-sectional piston forces, changes in buoyancy). Since it is common practice to make a preliminary tensional design using tubing weight loading only, a higher design factor is used for tension and especially for joint strength (Table 1, above). Some companies and more conservative engineers will even ignore the potential benefits of buoyancy. Buoyancy results in a piston force on the lower end of the tubing and as a first approximation it may normally be assumed that

(12) where: WB = buoyant weight WN = weight in air = density of steel (± 8 gm/cc) = density of fluid Figure 5 graphically depicts the tensional and compressional forces at work on a tapered string of tubular goods. The load resulting from the weight of the pipe is shown for a string weighed in air, and with the buoyant forces accounted for as piston forces or approximated using Equation 12. We can see that at a point approximately midway in the length of the heavier pipe at the bottom of the string there is a change from compression to tension. This is also the concept which guides the design of drillstrings with the purpose of keeping the drillpipe in tension while using the heavier drill collars to maintain a compressional load on the bit. Part 2 of Example 2 gives the preliminary tension design considerations for the completion already covered in part 1. Example 2 (part 2) Preliminary Tension Design

Tubing weight: 6.4 lb/ft Tubing length: 11,500 ft Packer fluid: inhibited oil 0.38 psi/ft = 0.88 gm/cc WN = 6.4 11,500 = 73,600 lb

= 0.89

73,600

= 65,504 lb Joint Specifications J55

L80

EUE

HYD CS

EUE

HYD A95

API joint strength (Klb)

99.7

100

135.9

128

Design factor (Table 1)

1.8

1.8

1.8

1.8

Design capacity (Klb)

55.4

55.6

75.5

71.1

Tubing Tension Design Considerations 1. Requires L80 tubing at surface 2. Requires joint strength capability of EUE or equivalent 3. In view of pressures, depth, and H2S would probably select premium grade coupling Many companies have these design techniques programmed for the computer and use the same general technique for both tubing and casing designs. Tubing Design Parameters It is important to remember that while the primary function of the tubing is as a conduit for hydrocarbon production or for injection of water or gas, the most severe loadings often occur during well service or killing operations, or during pressure tests. It is therefore prudent to make provision for these operations when designing a completion, and to check out the tubing limitations when planning a well servicing operation (e.g., a stimulation or a workover) . Care must be taken not to increase completion costs excessively by trying to make provisions for all sorts of unlikely, but possible, occurrences. It must also be remembered that there are steps that can be

taken to mitigate the induced stresses during many operations (e.g., applying annular pressure or heating fracturing fluids). On the other hand, the consequential costs of a failed tubing string, or of having to run a special working string, in terms of deferred production and rig time, can be quite substantial. Assessment of the most cost effective solution is generally a judgment call based on the engineer's experience and on corporate attitudes and policy. A typical set of parameters has already been illustrated in Example 2. Burst The tubing and wellhead should be designed for squeeze and kill conditions. Since fines in the perforations or oil can sometimes cause a "check valve" effect when attempting to squeeze back liquids, many completion designers like to have the flexibility of being able to raise the bottomhole pressure to the FBP or at least to the FPP. However, with high permeability reservoirs or gas wells in which fracture stimulation is unlikely, completion engineers are often satisfied with a certain minimum differential for injection. The value selected varies from area to area and from company to company, but is commonly either around 1000 psi (7 MPa), or 33% of the reservoir pressure. The author suggests 1. FBP where k1 < 100 md kg < 50 md 2. FPP for squeezing liquids, where k1 > 100 md 3. CIBHP + 1000 psi (7 MPa) for squeezing gas, where kg > 50 md; or for squeezing liquids, where k1 > 1000 md From the rock mechanics theory presented by Geertsma (1978) and others it may be deduced that in a tectonically relaxed area, a provisional estimate of the fracture propagation gradient (FPG) can be obtained from the equation

(13) FPG < FBG < 1.1 psi/ft (25 kPa/m) (14) where: sv = overburden stress ( ~1 psi/ft depth) p = pore pressure, psi D = depth, ft FPG = formation propagation gradient, psi/ft FBG = formation breakdown gradient, psi/ft The specification of the pressure test conditions is often critical to burst design. Government regulations sometimes specify pressure test conditions (e.g., to at least 90% of the reservoir pressure or to 1000 psi (5 MPa) over the maximum differential pressure expected at the packer). If no regulations exist, most operators test to their tubing design conditions.

Collapse Severe collapse loads on the tubing can occur in gas wells and high GOR oil wells with low-flowing bottom-hole pressures and deepset safety valves, after blowdown to test a plug, etc. during annulus pressure tests, or operation of shear circulation devices where there are pressured annuli during underbalance perforating or testing at high drawdown during tubing blowouts It is important to remember that tension reduces collapse strength. This biaxial effect should be examined for large diameter tubings, especially if reduced collapse design assumptions and/or a deep-set safety valve is used. Tension Tubing strings are not only subjected to running tensions with all the associated shock and acceleration loadings, but also to varying operating stresses due to piston forces on the steel and/or any plugs, pumps, standing valves, and the like in the tubing. Moreover, if the tubing is anchored or held by a packer, its operating tension will vary as a result of thermal effects (hot production or cold kill fluid) piston effects (changes in buoyancy and forces at joint upsets) ballooning effects (changes in internal or external pressure) buckling effects (longitudinal instability) These potential problems are listed in terms of their most common relative magnitude (although the relative importance of piston and ballooning effects is variable). Combined Loading While the designer of tubular goods normally talks in terms of burst, collapse, and tension compression as if they were independent, it is obvious that in most actual loading situations they occur simultaneously. Precise stress analysis should really consider a triaxial loading situation. The simultaneous solution of all the associated equations is rather complicated. A number of computer programs are available, but for most field engineers they will be a "black box" solution. This can be dangerous. It is important to check that the formulas are properly handled, particularly with respect to collapse, which is a "stability effect." Therefore it is usual for critical stress analyses (e.g., for ultra deep,

high pressure, or sour wells) to be undertaken by a specialist consultant, research group, or intracompany task force. Moreover, since this is not the routine design technique, design factors are less well proven (although a value of 1.25 is often used). A more convenient approach for the intermediate range, moderately complex design problem is to use the ellipse of biaxial yield stress proposed by Holmquist and Nadai (1939). The critical relationships are (a) tension reduces collapse resistance; (b) compression reduces burst resistance. The other important concept in the consideration of triaxial loads is that pressure changes affect axial stresses or cause tubing movement. This has been extensively discussed in SPE papers by Lubinski (1962), Hammerlindl (1977), and Stillebroer (1967). Bending Bending stresses can be significant in large tubulars. They are compressive in the inner wall and tensional in the outer wall, the most detrimental being

(15) where: R = the radius of curvature (ft) sb = bending stress E = Young's modulus (for steel, E = 30

106 psi)

do = outside diameter of the tubular Bending stresses result from both hole curvature and buckling. The effects of doglegs need only be considered if they are very severe (>10°/100 ft; 10°/30 m) or if very large tubing (5 1/2 to 7 in.; 140 to 178 mm) is being used.

Production Casing The production casing must be adequately sized for the planned completion. It will obviously affect the size of the other required casing strings, the bit selection, the capacity of the rig, and the overall well costs. The production casing must be designed for the loads that may be imposed during the producing life of the field. It is similar to tubing design in several ways. Burst Production casing must be designed to withstand the maximum closed-in tubing pressure that can be expected. If a packer has been used, this pressure is assumed to be applied at the top of a full column of packer fluid (i.e., for the case of a tubing

failure at the surface). We usually assume that the external pressure resisting burst is a water gradient. If the packer fluid is heavier than water the burst load will increase with depth. In the event that a snubbing operation could not be conveniently attempted if a tubing break occurs at the surface, the casing must be strong enough to withstand a bullhead squeeze on the live tubing string, in which case this would be the design criteria for the casing and wellhead. In many cases it may be necessary to design the casing for loads imposed during stimulation and pressure testing. Conversely, the casing capacity must be checked when designing a fracturing treatment. This is particularly important in wells where no packer is used. Collapse Production casing may be subject to complete evacuation during production operations if the well is operated on gas lift or pumped-off, or if the packer or workover fluid is lost into a depleted zone. As the pipe may have deteriorated before this occurs, a higher design factor (1.125+) is often used for production casing. Severe collapse loads may occur in situations in which thermal expansion of the annular fluid between the production and intermediate strings cannot be bled off (e.g., in some subsea wells). Increased loading should be assumed if live annuli are a feature of the area. Reduced loadings may be assumed if the wells will not be pumped off, gas lifted, or severely depleted. Severe collapse loads may exist in the pay section during high drawdown, underbalanced perforating and testing, and squeeze either or both cementation and fracturing ( Figure 1 , Collapse loads in the pay). It is highly advisable to maintain some set casing/tubing annulus pressure during such service operations.

Figure 1

Tension/Compression In high rate production areas and thermal wells, expansion of the production tubing may impose additional tension on the casing strings, via the packer. Couplings In high pressure (>5000 psi; 34 MPa), high temperature (>300° F; 422 K) and/or severely sour conditions, premium casing couplings are recommended. Material Selection In sour environments, material specification must consider the chances of H2S contamination of the casing/tubing annulus and the added possibility of temperature changes during stimulation affecting the stress corrosion tolerance of the pipe. Couplings There are many forms of coupling available, some of which have been dedicated to the public through the auspices of the API, while others are produced by, or under

license from, a specific manufacturer. It was, in fact, the need to obtain a standardization of thread forms and diameters that led to the formation of the API Committee on Standardization of Tubular Goods in 1924. The API couplings ( Figure 1 ,

Figure 1

Figure 2 and Figure 3 ,

Figure 2

Cutaways of basic types of couplings) are of three basic types: external upset (EUE), nonupset (NU), and integral joint.

Figure 3

Threads are of two main forms. The round API threads are weaker than the pipe body (i.e., <100% efficient). The buttress threads were developed by the National Tube Division of the United States Steel Corporation to provide a high strength coupling for deep, high pressure well service. This thread is used in a number of proprietary couplings, e.g., Hydril, VAM, Atlas-Bradford. All tapered threads achieve a seal by driving the pin and box surfaces together under sufficient stress to generate a bearing pressure exceeding any differential that is to be subsequently applied. However, a small spiral void is always left between the mating surfaces, and must be filled with solids in the form of thread compound. (This is the reason for careful specification of the compound in Bul 5 A2.) On API round threads, this void occurs between the crest and root of the mating threads, while on buttress threads it extends over the whole flank of the thread on the beveled side. To improve leak resistance, especially at elevated temperatures and under high pressure differential, the so-called "premium" seals were developed. These consist of either metal-to-metal seals on tapered portions of the pin and box surfaces or an elastomer seal ring, or both. This type of seal requires a high quality finish and precise gauging and inspection. The coupling is therefore more costly. Since API and

buttress threads have proven to be very reliable in the field, the decision to use the more expensive "premium" seals requires careful economic justification. In general, their application has proven valuable in highly corrosive conditions in high pressure gas wells or high pressure/high GOR oil wells, and in thermal wells subject to high compressive loads. They may be used where workover costs are high (e.g., offshore). In general, API tubulars are adequate for differential pressures of less than 5000 psi (34.4 MPa) and temperatures of less than 300° F (150° C), using high temperature thread compound. For corrosive conditions and continuous gas service, the pressure limit is often reduced to 2500 psi (17 MPa). Exercises

Oilfield Units The 2 7/8-in., 6.4 lb/ft, J-55 NU tubing string in a 6000-ft oil well was designed based on the tubing's buoyant weight in water. What additional load would be imposed on the tubing if a rod pump were to be pressure tested to 500 psi after the well had been operating for some time and the annulus pumped off? The well produces 30° API oil (SG: 0.876) with no water. If company policy dictates the use of a design factor of 1.5 for joint strength, can this pressure test be safely carried out?

SI Units The 73-mm (2 7/8-in.), 9.5 kgm/m (6.4 lb/ft), J-55 NU tubing string in an 1830-m oil well was designed based on the tubing's buoyant weight in water. What additional load is imposed on the tubing if a rod pump were to be pressure tested to 3.5 MPa after the well had been operating for some time and the annulus pumped off? The well produces 876 kg/m3 oil (SG 0.876) with no water. If company policy dictates the use of a design factor of 1.5 for joint strength, can this pressure test be safely carried out? Solutions

Oilfield Units Weight in air = 6000 ft x 6.4 = 38,400 lb

Buoyancy in water =

= 0.875

(density of water 1 gm/cc; density of steel = 8 gm/cc; use Equation 12)

(12)

Buoyant weight when run 38,400 x 0.875 = 33,600 lb Water gradient (SG = 1) = 0.433 psi/ft Oil gradient (SG = 0.876) = 0.876 x 0.433 = 0.379 psi/ft ID of tubing = 2.441 in., Ai = 4.680 in2 Weight of oil in tubing = 6000 x 0.379 x 4.680 = 10,642 lb Total applied tensile force at the surface, after well has been pumped off, equals Weight of oil + weight of tubing in dry casing + applied pressure x area of tubing ID = 10,642 + 38,400 + 500 (4.680) = 10,642 + 38,400 + 2340 = 51,382 lb The API joint strength rating of 2 7/8-in., 6.4 lb/ft, J-55, non-upset tubing = 72,600 lb. If a design factor of 1.5 for joint strength is dictated by company policy, the allowable tensile loading (with design factor) = (72,600) / (1.5) = 48,400 lb. Therefore, the proposed loading exceeds the design specifications and a leak might occur during the test. In fact, the loading exceeds design specs even without adding the 500 psi of wellhead pressure (actual load 49,042 lb compared with an allowable of 48,400 lb). However, using a 1.33 design factor for operating loading conditions, pressure tests of up to 1184 psi would be permissible: (72,600) (1.33) = 10,642 + 38,400 + pt (4.68) Pt = 1184 psi

SI Units Weight in air = 1830 x 9.5 = 17,385 kg = 170.5 kN

Buoyancy factor in water =

= 0.875

(density of water = 1 gm/cc; density of steel = 8 gm/cc; use Equation 12)

(12) Buoyant weight when run = 170.5 x 0.875 = 149.2 kN Water gradient (SG = 1.0) = 9.794 kPa/m Oil gradient (SG = 0.876) 0.876 x 9.794 = 8.579 kPa/m

ID of tubing = 62 mm, thus Ai = 30.19 x l0-4 m2 Weight of oil in tubing = (1830 m) (8.579 kPa/m) (3.019 x 10-3 m2) = 47.4 kN Total applied tensile force at the surface after well had been pumped off equals Weight of oil + weight of tubing in dry casing + applied pressure x area of tubing ID = 47.4 + 170.5 + 3500 (3.019 x 10-3) = 47.4 + 170.5 + 10.57 = 228.47 kN From Figure 1 , the API joint strength rating of 73-mm, 9.5 kgm/m, J-55, nonupset tubing is 72,600 lbs (322.92 kN).

Figure 1

If a design factor of 1.5 for joint strength is dictated by company policy, the allowable tensile loading (with design factor) = 322.92/1.5 = 215.28 kN

Therefore, the proposed loading exceeds the design specifications and a leak might occur during the test. In fact, the loading exceeds design specifications even at zero wellhead pressure (actual load of 47.4 + 170.5 = 217.90 kN compared with an allowable load of 215.28 kN). However, using the 1.33 design factor for operating loading conditions, pressure tests of up to 8252 kPa would be permissible:

= 217.90 + pt (30.19 x l0-4) pt = 8248 kPa

2.. Oilfield Units A 12,000-ft, hydrostatically pressured gas well ( g= 0.7) is to be completed. What closed-in tubing head pressure can be expected? If the casing, wellhead, and tubing are to be designed for a squeeze kill at fracture propagation pressure (FPP) what wellhead pressure would be expected at the start of the kill operation? (Use Equation 13 for estimating the FPG.)

(13)

SI units A 3660-m hydrostatically pressured gas well ( g = 0.7) is to be completed. What closed-in tubing head pressure is expected? If the casing, wellhead, and tubing are to be designed for a squeeze kill at fracture propagation pressure (FPP) what well-head pressure would be expected at the start of the kill operation? (Use Equation 13 for estimating the FPG.)

Solutions

Oilfield Units Condition

Loading

Design Criteria

Typical Design Factor

Burst

Internal

Kill pressure on hydrocarbon-filled tubing

1.125

External

Packer fluid and zero annulus pressure

Considerations

Check effects of compression

External

Casing head pressure=

Collapse

1.125

shut-in tubing pressure

Tension

Tension and Compression

Internal

Tubing empty and depressured

Considerations

Check effects of tension

Running

Buoyant weight in

Body: 1.333

completion fluid

Joint: 1.8*

Cold stimulation and hot production conditions

Body: 1.125

Operating

Joint: 1.333 Considerations

Total Stress

Check effects of temperature and pressure changes

Triaxial

Max. stress 80% yield

*Assuming separate checks are not planned on shock and bending effects; otherwise use 1.5. Table 1: Typical criteria for tubing design on a flowing well The ratio of THP to BHP for 

g

of 0.7 = 0.747.

At 12,000 ft, assuming a hydrostatic gradient of 0.433 psi/ft, the bottomhole pressure can be estimated as BHP = 12,000 x 0.433 = 5196 psi with gas surface pressure 5196 x 0.747 CITHP = 3881 psi Assuming the overburden gradient to be 1 psi/ft and using Equation 13 to estimate the fracture propagation pressure:

= 0.717 psi/ft FPP = 0.717

12,000 ft = 8604 psi

Maximum wellhead pressure at the start of the kill operation (THIP) will equal the formation propagation pressure minus the pressure due to the gas gradient:

THIP = (12,000 0.717) - (5196 - 3881) = 7289 psig More correctly, we should use the ratio in Table 1 since the increased pressure will increase the gas density. THIP = (12,000 0.717) 0.747 = 6427 psi Therefore, a 5000 psi wellhead should not be used even though the maximum closed-in tubing head pressure is only about 4000 psi.

SI Units Referring to Table 1: The ratio of THP to BHP for 

g

= 0.7 = 0.747

At 3660 m, assuming a normal hydrostatic pressure of 9.795 kPa/ m, bottomhole pressure can be estimated as BHP = 3660 9.795 = 35,850 kPa with gas surface pressure = 35,850 0.747 CITHP = 26,780 kPa Assuming the overburden gradient to be 22.62 kPa/m and using Equation 13 to estimate the fracture propagation pressure:

= 16.21 kPa/m FPP = 16.21

3660 = 59,329 kPa

Maximum wellhead pressure at the start of the kill operation (THIP) will equal the formation propagation pressure minus the pressure due to the gas gradient: THIP = (3660

16.21) - (35,850 - 26,780) = 50,259 kPa

More correctly, we should use the ratio in Table 1 since the increased pressure will increase the gas density: THIP = (3660 16.21) 0.747 = 44,319 kPa A 64 MPa wellhead should therefore be used.

3…Oilfield Units A 7000-ft well that is to be produced with a target of 15,000 STB/d using 5.5-in. tubing encounters 170 ft of oil-bearing formation with a pressure of 3000 psi. What rating of wellhead should be used? If a single grade and weight of tubing is to be

used, what is the cheapest string that can probably be run, assuming that

Grade

Weight (lb/ft)

Collapse Strength (psi)

Burst Strength (psi)

Tensional Strength (1000 lb)

Cost Comparison

J-55

15.5

4040

4810

300

cheapest

17.0

4910

5320

329

C-75

17.0

6070

7250 423

N-8O

17.0

6280

7740

446

20.0

8830

8990

524

most expensive moderately expensive

packer fluid: inhibited seawater (gradient = 0.435 psi/ft) reservoir pressure: 3000 psi kill pressure: > 1000 psi above CIBHP (squeezing gas) < fracture propagation pressure (squeezing oil) Fracture propagation pressure gradient (FPG) is approximately:

FPG = 0.5 + 0.5

(psi/ft)

If gas cap gas should break through into the well, assume gas gravity = 0.65. Use Table 1 to calculate head of gas.

Condition

Loading

Design Criteria

Typical Design Factor

Burst

Internal

Kill pressure on hydrocarbon- filled tubing

1.125

External

Packer fluid and zero annulus pressure

Considerations

Check effects of compression

External

Casing head pressure= shut-in tubing pressure

Internal

Tubing empty and

Collapse

1.125

depressured Considerations

Check effects of tension

Tension

Running

Buoyant weight in completion fluid

Body: 1.333 Joint: 1.8*

Tension and Compression

Operating

Cold stimulation and hot production conditions

Body: 1.125 Joint: 1.333

Considerations

Check effects of temperature and pressure changes

Total Stress

Triaxial

Max. stress 80% yield

*Assuming separate checks are not planned on shock and bending effects; otherwise use 1.5. Table 1: Typical criteria for tubing design on a flowing well. Assume live oil gradient is 0.3 psi/ft. Consider only the maximum burst at the wellhead, the maximum collapse load at the packer, and the running tension.

SI Units A 2130-m well that is to be produced with a target of 2400 m3/day of oil with l40mm (5 1/2-inch) tubing encounters 50 m of oil-bearing formation with a pressure of 20,700 kPa. What rating of wellhead should be used? If a single grade and weight of tubing is to be used, what is the cheapest string that can probably be run, assuming that

Grade

Collapse Strength

Burst Strength

Tensional Strength

(kPa)

(kPa)

(kN)

23.1

27,855

33,164

1,334

25.3

33,853

36,680

1,463

C-75

25.3

41,851

49,987

1,882

most expensive

N-80

25.3

43,299

53,365

1,984

moderately expensive

29.8

60,880

61,984

2,331

Weight (kgm/m)

J-55

Cost Comparison

cheapest

packer fluid: inhibited seawater (gradient = 9.840 kPa/m) reservoir pressure: 20,700 kPa kill pressure: > 7,000 kPa above CIBHP (squeezing gas) < fracture propagation pressure (squeezing oil) Fracture propagation pressure gradient (FPG) is approximately

FPG = (0.5) (22.3) + 0.5 kPa/m If gas cap gas should break through into the well, assume gas gravity = 0.65. Use Table 1 to calculate head of gas. Assume live oil gradient is 6.786 kPa/m. Consider only the maximum burst at the wellhead, the maximum collapse load at the packer, and the running tensions.

Solution

Oilfield Units CITHP = CIBHP -

o

D

o = 0.3 psi/ft under operating conditions: CITHP = 3000 - (0.3 7000) = 900 psi under maximum conditions (assuming gas breakthrough) CITHP = 0.854 x BHP (from Table 1) MAX CITHP = 0.854 x 3000 = 2562 psi under kill conditions:

FPG = 0.5 + 0.5 = 0.5 + 0.5 x = 0.71 psi/ft FPP = 7000 0.71 = 5000 psi

MAX BHIP (oil kill) = 5000 psi equivalent THP (oil kill) = 5000 - 0.3 x 7000 = 2900 psi In the case of a gas kill: MIN BHIP (gas kill) = 3000 + 1000 psi = 4000 psi equivalent THP (gas kill) = 0.854 x BHP = 0.854 x 4000 = 3416 psi From this we see that, while we could probably get away with a 3000 psi wellhead, strictly speaking we should be using a 5000 psi wellhead. Incorporation of the provision, in some regulations, for a wellhead rating equivalent to the reservoir pressure reflects this typical design for kill capability. Tubing Burst Rating burst rating = max THP

design factor

design factor = 1.125 required burst rating (for gas kill conditions) = 3416

1.125 = 3843 psi

All grades and weights satisfactory. Tubing Collapse Loading Calculation Calculate first assuming a high risk of gas breakthrough: head of packer fluid = ( f) (D) = (0.435) (7000) = 3045 psi max CHP = max CITHP (assumes leak) = 2562 psi max BH annulus pressure = 2562 + 3045 = 5607 psi

max collapse load = 5607 - 0 psi (assumes empty tubing) = 5607 psi design factor = 1.125 required collapse rating = 5607 x 1.125 psi = 6308 psi Therefore, strictly speaking, we should use 20-lb/ft, N-80 tubing, although it is more likely a l7.0lb/ft would be selected since the probability is very low that such severe collapse-loading assumptions would prove true. Calculate next assuming a low risk of gas breakthrough: max CHP = operating CITHP operating CITHP = 900 psi max BH annulus pressure = 900 + 3045 psi = 3945 psi max collapse load = 3945 psi required collapse rating = 3945 1.125 = 4438 psi We could select 17 lb/ft, J-55 tubing. Running Tension Calculations weight in air = W D = (17 lb/ft) (7000 ft) = 119,000 lb buoyancy factor = = = 0.8725 buoyant weight of tubing = 0.8725 119,000 lb = 104,000 lb design factor = 1.8 required tension rating = (104,000) (1.8) lb = 187,000 lb This can be easily carried by any of the tubing grades listed.

It is typical for collapse design to be the critical factor in high-rate, large-tubing completions, especially at relatively shallow depths. Conclusion: 5 1/2-in., 17.0-lb/ft, N-80 tubing meets all criteria for this type of production. Risk of gas breakthrough must be accurately assessed before choosing between N-80 and J55 grades. SI Units CITHP = CIBHP - o

xD

o =6.786 kPa/m under operating conditions: CITHP = 20,700 - (6.786 x 2130) = 6246 kPa under maximum conditions (gas breakthrough) CITHP = 0.854 x BHP (from Table 1) MAX CITHP = 0.854 x 20,700 = 17,678 kPa under kill conditions:

FPG = (0.5) (22.3) + 0.5 · = (0.5) (22.3) + 0.5 · = 16.00 kPa/m FPP = (2130) (16.00) = 34,080 kPa MAX BHIP (oil kill) = 34,080 kPa equivalent THP (oil kill) = 34,080 - (6.786 x 2130) = 19,626 kPa In the case of a gas kill: MIN BHIP (gas kill) = 20,700 + 7000 kPa = 27,700 kPa equivalent THP (gas kill) = 0.854 x BHP = 0.854 x 27,700 = 23,656 kPa From this we see that, while we could probably get away with a 20.7 MPa wellhead, strictly speaking we should be using a 34.5 MPa wellhead.

Incorporation of the provision, in some regulations, for a wellhead rating equivalent to the reservoir pressure reflects this typical design for kill capability. Tubing Burst Rating Calculation burst rating = max THP x design factor design factor = 1.125 required burst rating (for gas kill conditions) = 23,656 x 1.125 = 26,613 kPa All grades and weights satisfactory. Tubing Collapse Loading Calculate first assuming high risk of gas breakthrough: head of packer fluid = (f) (D) = (9.840) (2130) = 20,959 kPa max CHP = max CITHP (assumes leak) = 17,678 kPa max BH annulus pressure = 17,678 + 20,959 = 38,637 kPa max collapse load = 38,637 - 0 kPa (assumes empty tubing) = 38,637 kPa design factor = 1.125 required collapse rating = 38,637 x 1.125 = 43,467 kPa Therefore, strictly speaking, we should use a 29.8-kg/m, N-80 tubing, but more likely 25.3-kg/m tubing would be selected since the probability of such severe collapse loading is very low. Calculate next assuming low risk of gas breakthrough: max CHP = operating CITHP operating CITHP = 6246 kPa max BH annulus pressure = 6246 + 20,959 = 27,205 kPa max collapse load = 27,205 kPa

required collapse rating = 27,205 x 1.125 = 30,606 kPa We could select 25.3-kg/m, J-55 tubing. Running Tension Calculation weight in air = 25.3 2130 = 53,889 kg · m = 528.5 kN

buoyancy factor = = =0.8725 buoyant weight of tubing = 0.8725 528.5 kN = 461.1 kN design factor = 1.8 required tension rating = (461.1) (1.8) = 830 kN This can be easily carried by any of the tubing grades listed. It is typical for collapse design to be the critical factor in high-rate, large-tubing completions, especially at relatively shallow depths. Conclusion: 140-mm (5 1/2-inch), 25.3-kg/m, M-80 tubing meets all criteria for this type of production. Risk of gas breakthrough must be accurately assessed before choosing between M-80 and J-55 grades.

Packers Packer Functions A packer is a subsurface tool that provides a seal between the tubing and casing,thereby preventing the vertical movement of fluids across this sealing point. Packers are used for the following reasons: · to improve safety by providing a barrier to flow through the annulus

· to keep well fluids and pressures isolated from the casing · to improve flow conditions and prevent heading · to separate zones in the same wellbore · to place kill fluids or treating fluids in the casing annulus · to pack off perforations rather than use squeeze cementing · to keep gas lift or hydraulic power fluid injection pressure isolated from the formation · to anchor the tubing · to install a casing pump · to minimize heat losses by allowing the use of an empty annulus or thermal insulator · to isolate a casing leak or leaking liner lap · to facilitate temporary well service operations (e.g., stimulations, squeezes) Packer Types There are many packer manufacturers, some of whom offer an extensive variety of packers, with each differing to some degree from those of the other manufacturers. This rather bewildering array can, however, be grouped into principal classes or types, and may be further categorized by method of setting, by direction of pressure across the packer, and by the number of bores through the packer. Packers can be primarily classified as either retrievable, or permanent, or permanent-retrievable, or inflatable. Retrievable Packers This type of packer is run on the tubing ( Figure 1 , Retrievable packer).

Figure 1

After setting, it can be released and recovered from the well on the tubing. Since it is an integral part of the tubing string, the tubing cannot be removed from the well without pulling the packer, unless a detachable packer head is used. Retrievable packers may be designed to be set mechanically or hydraulically. Mechanical setting methods include rotation of the tubing string, reciprocation of the tubing string, or the application of tension or set-down weight. With mechanical packers, the tubing is usually set in compression. Hydraulic packers are set by applying hydraulic pressure through the tubing string, but once set they hold the set position mechanically. The tubing is usually in tension. Retrievable packers are usually used for complex multizone and multistring completions. Their main limitation was in their limited ability to accommodate tubing stress changes without unsetting; the availability of effective slip joints and detachable heads has eased this situation. An historical problem was failure of the internal elastomer seals, but this technology also has improved markedly in the last decade. All metal-to-metal seal packers are available but are expensive.

One disadvantage of retrievable packers is that if they fail to retrieve, they must be removed by milling them out of the casing with an abrasive milling head and a drillstring. They are very difficult to mill. Generally, this type of packer is used under nonsevere conditions (differential pressures less than 5000 psi (34.4 MPa), temperatures less than 300° F (422° K). Because of the setting mechanism, retrievable packers tend to have a restricted bore, compared with other packers designed for the same casing size. This factor may restrict flow or limit wireline operations below the packer depth. Permanent Packers Permanent packers are independent of the tubing and may be run on tubing or on wireline ( Figure 2 and Figure 3 ).

Figure 2

The tubing can be released from the packer and can be pulled, leaving the packer set in the casing.

Figure 3

Tubing can subsequently be run back and resealed in the packer. The packer may thus be considered an integral part of the casing. It is sometimes called either a production packer or a retainer-production packer. The permanent packer cannot be recovered as such, but it can be destructively removed (e.g., by milling) ( Figure 4 and Figure 5 ).

Figure 4

If the packer includes a tailpipe and must be recovered, a millout extension is needed on the packer for the "packer picker," or catch sleeve, on the mill to engage. In other cases, it may be adequate to simply push the packer to the bottom of the casing after milling.

Figure 5

Permanent packers can be set using an electric wireline setting tool, a hydraulic setting tool run on drillpipe or tubing, or by a combination of rotation and pull. Permanent packers are typically used when · formation, treating, or swabbing differential pressures will be high · it is desirable to pull the tubing without unseating the packer · it might be desirable to convert the packer to a temporary or permanent bridge plug · high bottomhole temperatures exist · tubing operating stress variations would not be accommodated with a retrievable packer without making it impossible to pull · a retrievable packer would have an inadequate bore Permanent-Retrievable Packers

A recent arrival, this type of packer has the same characteristics as the permanent packer, but it can, when desired, be released with a special pulling tool and recovered. Inflatable Packers These are packers with a flexible sealing element that can be expanded hydraulically using either completion fluid or cement. They are used as openhole packers, or when the casing is buckled or collapsed, preventing the usage of conventional packers. Inflatable packers cannot stand high pressure differentials and are generally limited to special applications, such as drillstem testing. Packer Failures The major causes of so-called "packer failures" relate to · use of the packer outside its operating range · unsetting of the packer or seal assembly as a result of pressure or temperature changes · using or setting the packer incorrectly · the packer being in poor condition when run Difficult operating conditions require more expensive equipment and more rigorous design work. It is important to remember that a packer is effectively a piston within the casing and will therefore be heavily affected by changes in differential pressure. Pressure from below or increasing string tension due to tubing contraction, or both, tend to unset the following: · weight-set packers · hydraulically set packers not equipped with holddown buttons · locator seal assemblies or overshots Pressure from above tends to unset tension-set packers or cause collapse-type failures or leakage at seal assemblies under high pressure differentials.

Tubing/Packer Forces and Movement Changes in temperature and pressure inside and outside the tubing affect the length of the tubing string (if the string is designed to permit motion) and the forces exerted at the packer (if no motion is permitted). These changes in tubing length or force between producing and pump-in conditions can be large, and should be considered in choosing a packer. This is especially important in high temperature (usually deep) wells, and may limit the use of

retrievable packers. Design of slip joints and seal assemblies must also consider these forces. (The following section draws heavily on the work of D.J. Hammerlindl (1977) and Arco as published in JPT February 1977, and on that of Arthur Lubinski, W. S. Althouse, and T. L. Logan (1962).) Factors Causing Packer Forces or Tubing Movement If the tubing string is free to move, its length will change as a result of temperature and pressure influences, which may be subdivided into thermal, piston force, ballooning, and buckling effects. Consideration of these effects will determine the seal length required and/or slip joint design. If the tubing is anchored to the packer, these effects will result in a change In the axial tension in the tubing. This can affect not only the design of the uppermost tubing joint, but also packer shear pin rating and the degree of buckling above the packer and therefore the through-bore access. A mechanical force is also involved in this situation. To consider these effects, it is necessary to define the critical conditions to be examined. These normally include: landing conditions; operating conditions; shut-in conditions; killing/stimulating conditions; pressure test conditions. Initial calculations are made for a set of assumed landing conditions, e.g., -50,000 to +50,000 lb (-225 to +225 kN) tension (-) or compression (+). For convenience a designer may sometimes choose to examine only the differences between what are considered to be the most severe conditions (i.e., hot producing to cold stimulating); however, these are not always apparent (e.g., pressure test loads can be the most severe). Mechanical Forces Mechanical forces can be subdivided into tension and compression. Tension results in the stretching of tubing string. The elongation due to tension forces can be determined by Hooke's law, which states that the change in length is directly proportional to the applied force. The equation for Hooke's law in this application is as follows:

(16) where:

= length change (inches) L = tubing length (inches) Ft = tensional force (-) (lbf) E = Young's modulus (30 106 psi) As = cross-sectional area of the tubing wall (in2) This relationship is the basis of the tubing stretch tables and graphs published by various equipment manufacturers. Temperature or Thermal Effects The length change due to change in temperature is equal to the length of the tubing, times the coefficient of thermal expansion for steel, times the change in average temperature:

Since (17) then (18) where: = change in tensional force in tubing at the surface due to temperature change As the coefficient of thermal expansion for steel () is 6.9 l0-6/°F (12.42 l0-6/°C) and Young's modulus (E) is 30 x 106 psi (207 GPa): = -207 As T lb/°F Ft = -2.57 As T N/°C In most cases, it is adequate to deal with the change in the average string temperature. It is often assumed that the completion is at geothermal gradient when landed (1 to 2° F/100 ft, or 1.8 to 3.6° C/100 m) during stimulation/killing it will stabilize within 20° F (10° C) of ambient temperature The temperature during producing conditions is a function of flow rate, gas expansion, geothermal gradient, thermal insulation of the tubing, and the like. Various computer programs are available to calculate this in critical cases, but it is usually adequate to use data from offsets producing under similar conditions. Production test data should be used judiciously since test rates and flow periods are often too low and too short for thermal stabilization to occur. As a first approximation designers will often assume a flowing gradient for high rate wells of 0.4 °F/100 ft, or 0.7 °C/100 m. Piston Force Effects The most familiar form of piston force is that of the stretch and/or stress induced when making an internal pressure test against a plug set inside a string of tubing.

The force against the plug is equal to the pressure applied times the cross-sectional area of the tubing ID: Fp = pt Ai (19) For example, a 10,000 psi (69,000 kPa) pressure test on 3 1/2-in. (89 mm) tubing (I.D. 2.992 in.) should result in a force of Fp = 10,000 (2.992)2 = 70,000 lb (311,000 N) Where the tubing is inserted into a packer we must similarly consider the piston effects on the cross section of the steel as it is affected by changes in the internal and external pressure. The piston force at the packer related to a change in the inside and outside pressures is Fp = (Ap - Ai)

pi - (Ap - Ao)

po

(20)

where: Ap = area of packer bore Ai = area of tubing ID Ao = area of tubing OD The change in tubing length related to this piston force is (21) where the pi and po changes are considered positive if they correspond to an increase and negative if they correspond to a decrease in pressure ( Figure 1 , Schematic showing piston force at the packer related to a change in the inside and outside pressures).

Figure 1

The piston forces are, in essence, the change in the buoyant force on the tubing. Ballooning Effects As the pressure inside the tubing increases, the pipe expands radially. This will cause an axial shortening. Application of pressure to the annulus will cause the tubing diameter to contract (reverse ballooning). This will result in a tubing elongation. The length change accounts for the change in radial pressure forces due to surface pressure changes (pis and pos) and fluid density changes (i and o) as well as flow inside the tubing ( ). The formula for calculating the change in length due to ballooning is

(22) where: = Poisson's ratio of the material (for steel = 0.3) R = ratio OD/ID of the tubing  = drop in pressure in the tubing per unit length due to flow. The pressure drop is positive when the flow is downward and zero when there is no flow. i = density of fluid inside tubing o = density of fluid outside tubing pis = surface tubing pressure pos = surface annulus pressure Buckling Effects Buckling is caused by two effects: applied longitudinal compression loads and internal pressure. The first is easy to understand as a logical consequence of the loading of a column. However, the buckling of a pipe under tension as a result of internal pressure is a difficult concept to appreciate. One way to visualize this type of buckling is to consider a slightly banana-shaped tubing joint subject to internal pressure ( Figure 2 and Figure 3 , Causes of buckling).

Figure 2

There will be a small unopposed area upon which the pressure will act to cause distortion of the pipe.

Figure 3

The resulting buckling will reflect the balance of strain and bending energy. This is similar to having a "fictitious force" (Ff) acting on the end of the pipe. To better understand buckling resulting from compression loading, consider a string of tubing freely suspended inside the casing. Now consider an upward force, F, applied to the lower end of the tubing. This force compresses the string and buckles the lower portion of the string into a helix. The neutral point is where the buckling stops. This force decreases with increasing distance from the bottom of the string and becomes zero at the neutral point. The distance, n, from the bottom of the tubing to the neutral point is calculated from the following formula:

(23) where: W = Ws + iAi - oAo, representing the buoyed weight of the tubing per unit length F = the force applied to the lower end It should be understood that in the presence of fluids the neutral point is not the point at which there is neither tension nor compression, but it is the point below which the string is buckled and above which the string is straight.

If the neutral point is within the string, then the shortening of the string due to buckling (Lb) is as follows:

(24) where I is the moment of inertia of tubing cross section with respect to its diameter:

I=

(D4 - d4)

When the calculated value of the neutral point is above the upper end of the string, the entire string buckles into a helix. When the pressure inside the tubing (Pi) is greater than the pressure outside (po) at the packer, a shortening will occur due to helical buckling. It was determined by Lubinski, Althouse, and Logan (1962) that, as far as the buckling is concerned, the tubing behaves as if subject to the following "fictitious" force:

Ff = A (p - p ) (25) Because part of this force, Ff, appears to be nonexistent, the entire force, F, was given the name p

i

o

fictitious. Further, it was determined that the string would buckle if Ff is positive and would remain straight if Ff is zero or negative. Substitution into Equation 24 gives

(26) where Lb is the change in length with respect to the length of the tubing when landed with p i

p

=

o

If the pressure outside the tubing is greater than the pressure inside the tubing at the packer (po > pi), there is no helical buckling due to pressure. The total change in tubing length as a result of these various factors (mechanical and piston forces, and thermal, ballooning, and buckling effects) may be expressed as

L = Lm + Lt + Lp + LB + Lb (27) The effect of this net change in tubing length on the tubing stress will depend upon the amount of motion permitted by the packer design. Permanent Corkscrewing If the buckling results in the yield strength of the tubing being exceeded, permanent corkscrewing can occur. In addition to the stresses of helical buckling, the tubing is subject to elongational stresses, as well as tangential and radial stresses due to pressure inside and outside the tubing. A triaxial stress analysis must be made where conditions suggest that significant tubing stress will result. All the major equipment suppliers have computer and hand calculator programs available for making these computations. This service is usually available free to purchasers. The production engineer should spend some time determining the pressure and temperature conditions to be expected. Typically, a series of calculations is made for various

landing assumptions and the results plotted for analysis. It is also useful to make at least one hand calculation as a cross-check on the data received.

Exercise 1.. Oilfield Units A 10,000-ft, high-rate oil well is completed with 5 1/2-in., 15.5-lb/ft tubing (wall thickness 0.275 in.). Under producing conditions the flowing temperature gradient is 0.4 °F/l00 ft and under static conditions the geothermal gradient is 1.8 °F/100 ft from a mean surface temperature of 40 °F. When the well is killed with a large volume of 40 °F seawater, the bottomhole temperature drops to 70 °F. If free to move, what tubing movement can be expected from the landing condition to the hot producing and to the cold injection conditions? If a hydraulic packer were to be used and set in 30,000 lb of tension, what would be the tension loading on the packer after killing the well? (Use Equation 18 and ignore piston, ballooning, and buckling effects.) (18)

SI Units A 3050-m, high-rate oil well is completed with 140-mm, 23.1-kgm/m tubing (wall thickness = 7 mm). Under producing conditions, the flowing temperature gradient is 0.73 °C/100 m and under static conditions the geothermal gradient is 3.28 °C/l00 m for a mean surface temperature of 5.0 °C. When the well is killed with a large volume of 5.0 °C seawater, the bottomhole temperature drops to 21.0 °C. If free to move, what tubing movement can be expected from the loading condition to the hot producing and to the cold injection conditions? If a hydraulic packer were to be used and set in 133.45 kN tension, what would the tension loading on the packer be after killing the well? (Use Equation 18 and ignore piston, ballooning, and buckling effects.)

Solution Oilfield Units Reservoir temperature = 40 + (1.8 x 10,000 ÷ 100) = 220 °F Temperature loss up the tubing = 0.4 x 10,000 ÷ 100 = 40 °F Flowing tubing head temperature = 220 - 40 = 180oF From landing conditions to producing conditions

Lt = (L) ( ) (

T)

= (10,000) (6.9 where

10-6) (

T)

T=

Landing

= 130°F

Producing

= 200°F T=

= 200 - 130 = 70°F

Lt = (10,000) (6.9 x 10-6) (70) = +4.83 ft where: 1

= initial average temperature in tubing string

2 = final average temperature in tubing string Tsurf = surface tubing string temperature TBH = bottomhole tubing string temperature From producing to injection conditions:

Producing

Injection

= 200 °F

= 55 °F

T= = 55 - 200 = -145°F Lt = (L) ( ) ( T) = (10,000) (6.9 10-6) (-145) = -10.00 ft Therefore, the maximum overall length change is -10 ft, from producing to injection. Equation 18 states the change in tension to be Ft = -E( ) (As) ( T) for tubing with OD = 5.5 in., and ID = 4.95 in.:

= 4.51 in2 Between landing and injecting conditions, the apparent force acting on the tubing to cause the contraction effect is

Ft = (-E) ( ) (As) ( T) = -(30 x 106) (6.9 10-6) (4.51) (55 - 130) = +70,017 lb force To maintain the original tubing length, the packer must exert an equal and opposite force: Fp = -70,017 lb f (tension) If the tubing was landed in 30,000 lb tension, the net tension at the packer level is Fp = -70,017 - 30,000 Fp = -100,017 lb force (tension) This is well in excess of feasible shear pin arrangements and therefore a hydraulic packer cannot be used. This well should be completed with a permanent packer and a locator seal assembly of seal receptacle permitting 10 ft of travel.

SI Units Reservoir temperature = 5 +

= 105.0 °C

Temperature loss up the tubing (flowing) =

0.73 = 22.3 °C Flowing tubing head temperature = 105.0 - 22.3 = 82.7°C From loading conditions to producing conditions Lt = (L) ( ) (

T)

= (3050) (12.42 where

T=

2

-

l0-6) (

T)

1

Landing

= 55°C

Producing

= 93.9°C T=

2

-

1

= 93.9 - 55 = 39.9°C

Lt = (3050) (12.42 x 10-6) (38.9) = 1.47 m where: 1

= initial average temperature in tubing string

2 = final average temperature in tubing string Tsurf = surface tubing string temperature TBH = bottomhole tubing string temperature

From producing to cold injection conditions

Producing

Injection

= 93.9°C

= 13.0°C

T = 2 - 1 = 13.0 - 93.9 = -80.9°C Lt = (L) ( ) ( T) = (3050) (12.42 10-6) (-80.9) = -3.06 m Therefore, the maximum overall length change is 3.06 m from production to injection. Equation 18 states the change in tension to be Ft = -E( ) (As) ( T) for tubing, with OD = 140 mm, and ID = 126 mm: As = (1402 - 1262) mm2 = 2.925 10-3 m2 Between landing and injection conditions the apparent force acting on the tubing to cause the contraction effects is Ft = (-E) ( ) (As) ( T) = -(206.8 106) (12.42 10-6) (2.925 10-3) (13.0 - 55.0) Ft = +315.53 kN To maintain the original tubing length, the packer must exert an equal and opposite force: Fp = -315.53 kN If the tubing was landed in 133.45 kN tension, the net load at the packer is Fp = -315.53 - 133.45 = -448.98 kN tensile force This is well in excess of feasible shear pin arrangements and therefore a hydraulic set packer cannot be used. This well should be completed with a permanent packer and a locator seal assembly or seal receptacle permitting 3 m of travel.

Artificial Lift Equipment Anchors Unanchored tubing in a rod-pumped well will be subject to constant movement. The tubing will buckle on the upstroke and stretch on the downstroke. This is sometimes called "breathing." This movement leads to wear and fatigue problems and can result in inefficient use of the available pumping unit stroke. Tubing anchors are used to minimize this movement. Tubing anchors are classified as follows:

· tension anchors, which permit the tubing to elongate but not to shorten · compression anchors, which permit shortening but not elongation · fixed anchors Compression anchors reduce the breathing problems but do not prevent buckling and are therefore rarely used. Tension anchors, which gradually "walk down" the inside of the casing as the pump starts to operate and then set the tubing at its maximum elongation, may damage the casing by repeated slight movement. Therefore, most anchors used today are of the fixed type (often miscalled tension anchors) ( Figure 1 ,

Figure 1

Mechanically set anchor, Figure 2 ,

Figure 2

Dual hydraulically set anchor, and Figure 3 , Single hydraulically set anchor).

Figure 3

There are two main setting mechanisms: · rotation set · hydraulic set It is best to select an anchor with a back-up retrieving mechanism so that if the primary one (i.e., rotation) fails, a secondary release (i.e., shear pins) can be used. Some hydraulic anchors depend only upon the differential pressure between the tubing and casing. These have an additional application in preventing seal assemblies or packers from becoming unlatched during stimulation operations.

Bottomhole Pumps Details of the bottomhole pump for rod-pumped wells are set out in API Spec 11AX, which includes a 12-character code to specify each pump type. The most critical is the second group which is the pump bore (125 to 275 corresponding to 1 1/4 in. to 2 3/4 in. or 32 to 70 mm) and the pump type (R-rod and T-tubing).

The pump displacement in oil field units can be obtained from PD = Ep

0.1166 S Es N D2

(28)

where: S = stroke (in.); say, 74 in. Ep = pump efficiency; assume 90% N = pump rate; say, 20 SPM Es = stroke efficiency (or rod stretch); assume 80% D = pump bore; say, 2 in. SN < 1500 in./minute (maximum desirable for rod fall) Using the numbers given above, the pump rate would be PD = 497 B/d (79 m3/d)

Downhole Completion Accessories Seating Nipples There are three main types of seating nipple used as integral parts of the tubing string: · pump-seating nipples · selective landing nipples · nonselective or no-go landing nipples Seating nipples, which are used to accommodate a pump, plug, hanger, or flow control device, consist of a polished bore with an internal diameter just less than the tubing drift diameter. Usually a lock profile is also required, especially for landing nipples. Heavy duty tubing sections, called flow couplings, are often run on either end of a seating nipple to minimize the effects of turbulence ( Figure 1 , Landing nipple and flow coupling installation).

Figure 1

Seating nipples and the devices that are set inside them are used for the following purposes: · to facilitate pressure testing of the bottomhole assembly and tubing couplings, and the setting of hydraulic packers · to land and seal off a bottomhole pump (pump seating nipple) · to isolate the tubing if it is to be run dry for high draw-down perforating · to land wireline retrievable flow controls, such as plugs, tubing safety valves, bottomhole chokes, and regulators · to plug the well if the tree must be removed · to land bottomhole pressure bombs · to pack-off across blast joints · to install a standing valve for intermittent gas lift

· to plug the tailpipe below packer in order to pull the tubing without killing the well · to temporarily plug the well while the rig is moved on or off the well Selective Landing Nipples Selective landing nipples are nipples with a common internal diameter. In some, the lock profile is varied for easy identification ( Figure 2 ,

Figure 2

Figure 3 ,

Figure 3

Figure 4 and Figure 5 , Landing nipples and locking mandrels).

Figure 4

Others are accessed by tripping the lock mechanism at the selected depth.

Figure 5

Selective nipples are used when more than one nipple is required within a single string of tubing, and the designer wishes to maintain maximum throughbore. They should be no closer than 30 ft (10 m) from a similar profile, and at least 10 ft (3 m) from any change in diameter. No-Go Landing Nipples No-go landing nipples are designed with an ID that is slightly restricted to provide a positive shoulder to locate a locking mandrel. The ID of these nipples should be checked against the dimensions of any through-tubing equipment that may be used. This type of nipple is usually located at the bottom of the tubing string or tailpipe and at least 5 ft below any profile change. In tailpipe installations, it is best to include a sliding sleeve above the nipple in case debris prevents the pulling of any plug set in the nipple by regular wireline methods. Alternatively, a mechanical perforator may be used to punch a hole above the plug. Sliding Sleeves

Also referred to as sliding side doors or circulating sleeves, these tubing components are used to obtain access from the tubing to the tubing/casing annulus either for fluid circulation or to permit a previously isolated zone to be produced ( Figure 1 , Sliding sleeves). They are opened and closed with a wireline tool that has a locating key that engages the profile in the sleeve. A TFL version is also available for subsea completions.

Figure 1

These devices are typically placed above each packer in the well. Obviously they are an essential requirement of multizone completions scheduled for selective production. Many producers run sliding sleeves in each string in a multistring completion to increase production flexibility. A sleeve above the upper packer is particularly useful for the following operations: · kick-off by displacing the tubing contents with a low density fluid, thereby avoiding the use of coiled tubing within the tubing · well killing prior to a tubing pulling job or workover

· circulating out completion fluid with a packer fluid (e.g., from mud to brine or from water to inhibited brine) · testing of subsurface safety valve (SSSV) · temporarily producing a selective zone into the tubing so it can be tested or so a bottomhole pressure survey can be obtained. The quality of the elastomer seals in sliding sleeves has improved greatly over the last decade. They are now much easier to open and less prone to failure. Special elastomers are needed for some well fluids and suitable design procedures are now available for elastomers. A ported nipple is sometimes used in place of a sliding sleeve, although this makes it necessary to pull the tubing string in order to stop annular access. Alternatively, some completion engineers prefer to use a side pocket mandrel and valve as a circulation point above the packer. Note, however, that side pocket mandrels offer a reduced area to flow and restrict circulation rates.

Side Pocket Mandrels Side pocket mandrels are a special eccentric nipple that can accommodate a valve in parallel to the tubing to control access to the annulus ( Figure 1 , Side pocket mandrels). They are used to install wireline retrievable gas-lift valves, circulation devices, flow control valves, and injection valves.

Figure 1

The location of side pocket mandrels for gas-lift valves will be determined by the lift gas pressure available and kickoff requirements. It is highly desirable to have one or two mandrels located just above the top packer in high pressure gas well completions. These are used to facilitate a controlled circulation kill in the event the sliding sleeve is inaccessible or if corrosion-inhibitor injection is required. Inhibitor may be supplied either through the annulus or via a special control line, continuously or in batch treatments. Some operators also use side pocket mandrels to install a pressure and temperature sensor that can transmit data to the surface via a cable attached to the outside of the tubing. Some engineers prefer to use a side pocket mandrel instead of a sliding sleeve above the top packer, since the elastomer seals on a side pocket circulation valve are easily retrieved and redressed using wireline, while repair of those in a sliding sleeve requires a workover. However, most circulation valves have a limited throughput capacity (0.5 b/m or 5 m3/hr) and some operators therefore have a tendency to pull the valve to increase circulation capability. This can result in a cutting out of the valve seat in the mandrel, which inevitably requires a workover to replace the mandrel.

Blast Joints and Flow Couplings Blast joints and flow couplings are special joints having the same nominal ID as the tubing, but a greater OD. They are usually manufactured from special heat-treated steel ( Figure 1 ,

Figure 1

Blast joints, Figure 2 ,

Figure 2

Polished nipples, and Figure 3 , Schematic of polished nipple run to provide sealing surface in case of blast joint erosion).

Figure 3

While they do not prevent erosion from occurring, their greater thickness can delay the time to erosion-caused failures. Blast Joints Blast joints are used to increase the abrasion resistance of the tubing string against the jetting action of a producing formation. Blast joints should be located in the tubing string opposite all upper perforations spanned by the tubing. Blast joints should also be used in the wellhead area where abrasive fracturing fluids may be pumped into the casing access. Polished nipples are sometimes included in the tubing string on either end of a blast joint in order to provide sealing surfaces for a spacer pipe should the blast joint fail. Flow couplings Flow couplings should be run immediately above each selective or no-go landing nipple in the tubing string that may be used to locate a flow control device. In high rate or corrosive gas wells, flow couplings should be used above and below all upsets or profile changes to reduce erosion, especially if the turbulent fluid contains abrasive

particles. Since most flow controls restrict the tubing ID, the tubing above and below the controls should be protected by use of a flow coupling.

Subsurface Safety Valves (SSSVs) Application of Downhole Safety Valves An SSSV must be installed in all offshore wells capable of flow and at onshore locations in high pressure or sour gas wells in close proximity to housing, public roads, or rock slide areas. These requirements are often dictated by government regulations and/or corporate policy. The objective is to provide a downhole shut-off that will limit the magnitude and consequences of the hydrocarbon emission if the primary well control device at the surface (e.g., Christmas tree) is damaged or cannot be operated. This could occur if a platform was damaged by a storm or major vessel impact, an explosion, a blowout, or by foundation instability. Similarly, on land a landslide or vehicle impact might knock off the well-head. There are several different types of subsurface safety valves. Flow-Controlled Safety Valves These are usually deep-set valves whose operation is directly controlled by the well stream. They are normally wireline retrievable since they must be reset from time to time, especially as well conditions change. They are designed to be open normally, but to snap shut if the tubing pressure dips below a threshold or the production rate exceeds a preset limit ( Figure 1 and Figure 2 , Flow-controlled safety valves).

Figure 1

Figure 2

They normally use spring tension to hold the valve open. The flow passes through a flow tube containing a bean. If the pressure drop across the bean exceeds the spring tension the valve will snap closed. The valve can be a ball, flapper, or stem type. The safety valve is reopened by raising the pressure on the downstream side in excess of the closed-in bottomhole pressure. Obviously, setting this type of valve requires an accurate knowledge of well behavior, temperature, and flow conditions. The major advantage of these valves is that they are cheap and can be set deep in the well below the packer, protecting both the tubing and annulus. The main disadvantages are the servicing and design requirements, the restrictions to flow capacity and flexibility, and the risk of inadvertent reopening as a result of fluids lost into the wellbore (e.g., seawater or mud in the event of an offshore collision of a boat with a wellhead). Surface-Controlled Subsurface Safety Valves (SCSSSVs) The SCSSSV is a fail-close valve that is held open by a high pressure control line ( Figure 1 , Tubing-retrievable, surface controlled, subsurface safety valve).

Figure 1

If the control line is severed in an event that damages the tubing or wellhead, pressure will leak off and the safety valve will close. The control line is generally connected to an emergency shutdown system to give automatic closure during unsafe or alarm conditions (such as fire or detection of gas). There is usually a control panel with pressure gauges and control valves for all of the wells on an offshore platform. Surface-controlled valves are the type of downhole safety valve most commonly favored today. In some countries, the regulations require the use of this type of valve in all offshore wells and onshore sour wells capable of flow. There are two basic types of SCSSSV: wireline retrievable (TFL retrievable) and tubing retrievable. With the wireline retrievable valve, an SSSV landing nipple is installed in the tubing string. This is basically a landing nipple with a port through which the control line enters between a set of packings on the SSSV. The SSSV is installed across this nipple. This type of valve can have a service life of 18 to 24 months or longer, although many valves fail during periodic testing. The relative ease of servicing and replacing wireline retrievable valves therefore offers distinct advantages. The main disadvantages of wireline retrievable SSSVs are that · the service life is short

· the restricted throughbore means the valve has to be pulled for deep wireline or through-tubing work · the turbulence in the flow stream increases pressure loss and erosion problems · we are forced to rely on a lock to make sure the valve is not blown out of the well on closure On the other hand, the initial costs are relatively low and servicing can be undertaken with minimal disruption to production. The tubing-retrievable SSSV valve is an integral part of the tubing string. As a result, it generally has a larger through-bore than the retrievable-type valves and may even be designed with an internal diameter that is the same as the tubing (a fullbore valve). Also, it is not so dependent upon elastomer seals and therefore has a much longer service life (5 to 20 years, depending on design and materials selected) . Tubing-retrievable valves with all metal-to-metal seals are available for severe environments. Since most valve failures are caused by elastomer problems and since tubingretrievable valves require a rig entry for repair work, these valves are often backed up with a nipple section positioned to accept a wireline-retrievable valve. Use of this valve insert minimizes the impact of a valve failure on production. This feature is incorporated in tubing retrievable valves together with a lock-out sleeve for the original valve, to lock it permanently open. Service procedures have been developed for installing the insert valve using both TFL and wireline techniques. To reduce the number of critical seals, many companies prefer single-control line valves. Although spring design does limit the depth to which this type of valve can be set, technology improvements have pushed the limit from around 650 ft (200 m) to in excess of 3250 ft (1000 m). Balance-line valves (valves with two control lines, one to close and one to open), which were developed to overcome the earlier depth limitations, are therefore becoming less popular. However, they have an advantage in that they can be pumped closed to facilitate the cutting of an obstruction in the valve, such as wireline. A balance-line valve can also be set at any depth, the critical issue being the closing time and control line efficiency. Protection systems for the control lines have been considerably improved over the last decade so that installation damage is much less common. New hydraulic fluids have also reduced control line pressure losses, so that it is possible to set a balance-line valve at the packer level. Field trials are also in progress on the use of electrical control systems for deep-set surface-controlled subsurface safety valves. The SCSSSV may incorporate a ball valve or a flapper valve. Ball valves are often considered more robust and can sometimes cut wireline when they are closed with it across the valve. However, they are prone to damage by sand and improper operation. The simpler flapper valve has the advantage of always being reopenable (mechanically if necessary) should it become stuck in the closed position. Extensive studies have shown that flapper valves are more reliable than ball valves; as a result, most operators run flapper style SCSSSVs. Operators also have the choice of running

tubing-retrievable SCSSSVs with lockout option. These valves offer redundancy (i.e., the ability to lock open one valve and run a second valve inside). Sleeve-type valves are also available. Setting Depth The recommended setting depth for a safety valve is often a matter of company philosophy and operating procedure. Where concurrent drilling and production is undertaken, many companies like to set the safety valve beyond the kickoff point so that it can be used to shut in the well during the tophole drilling and kickoff of an adjacent well. Other designers prefer not to subject the valve to significant bending and therefore favor its installation nearer to the surface. Subsurface safety valves are normally set at least 150 ft (50 m) below the surface or sea floor. Bottomhole Chokes and Regulators These are not safety devices in the strict sense of the word; however they are often used with the objective of limiting the rate at which a well could produce and therefore blowout, limiting the surface operating pressures in high pressure wells, and limiting the drawdown rates on wells that have a tendency to produce sand. They are also used to take maximum advantage of the formation temperature to avoid hydrate formation during choking of a high pressure gas stream at surface temperatures. Chokes are designed to give a constant rate, while regulators give constant choking or pressure differential. The other safety device that is often used in injection wells is a simple check valve that will permit injection but not production. This device may be used to prevent backflow of water and formation sand, should injection cease. All of these devices are normally wireline retrievable.

Wellhead Equipment Wellheads Wellheads typically are the joint responsibility of the production department (tubing head and Christmas tree) and drilling department (casing head and intermediate casing head). Figure 1 shows a typical flanged wellhead.

Figure 1

The size and pressure ratings of wellheads are dictated by the design considerations for the tubulars (e.g., tubing size, casing size, kill and stimulation pressure requirements, flowing pressure requirements). However, government regulations sometimes require that the rating of the upper part of the wellhead be at least equal to the reservoir pressure. Wellhead specifications are presented in API Spec. 6A. The standard wellhead ratings are 1000, 2000, 3000, 5000, 10,000, 15,000, and 20,000 psi (7, 14, 21, 34, 69, 103, 130 MPa). Wellhead components are generally flanged, although threaded components are permitted on low pressure wellheads with pressures less than 2000 psi (14 MPa). Threaded valve and choke connections can be used with pressures of up to 5000 psi (34 MPa) in wells less than 12,000 ft (3700 m) deep, but are not recommended. Clamped connections are sometimes used in the intermediate pressure range 2000 to 10,000 psi (14 to 69 MPa) ( Figure 2 , Wellhead and Christmas tree for a dualtubing completion utilizing clamp-type connections). For wells producing H2S gas, the wellhead materials must conform to NACE specifications.

Figure 2

Tubing Heads and Hangers The tubing head packs off around the production casing ( Figure 1 , Tubing head and tubing hanger installation).

Figure 1

It should have an outlet for access to the tubing/casing annulus, with an internal thread to receive a plug when redressing of the side outlet valve is necessary. The rating of the upper flange must be compatible with the Christmas tree. The tubing head should have lock-down screws for the hanger, and the lower flange size and rating must be compatible with the casing head flange. The bore and size of the top flange are generally determined by completion and well servicing requirements (BOP size, packer, and tool ODs) rather than the Christmas tree flange size. Like the casing, the pressure rating of the tubing head spool is often dictated by stimulation pressure requirements and may therefore be of a higher rating than the Christmas tree, which can be removed or protected during stimulation. Offshore, a compact wellhead, or unihead, is often used to combine both the casing and tubing spool's function and reduce the overall height of the wellhead. Three types of tubing hangers are commonly used:

· the boll weevil (also called a threaded mandrel) hanger, which is an integral part of the tubing string and therefore a fixed point that shoulders into the tubing head spool ( Figure 2 , Boll weevil tubing hanger)

Figure 2

· the wrap around hanger, which is hinged to permit installation onto any part of the tubing other than a coupling · the dual hanger, either multibore mandrel or split hanger The mandrel types are the most common. It is highly desirable to have an internal thread in the tubing hanger to allow the installation of a back pressure valve while removing, repairing, or pressure testing the tree. This can be installed and removed under pressure with a special tool.

Christmas Trees (see Figure 1 , Typical flanged wellhead)

Figure 1

There are three main types of trees: the assembled tree, the solid block tree, and the control head tree (often found on thermal wells). The major components (from bottom up) are the flange the master valve(s) the tee or flow cross the swab valve the crown plug the wing valve the bean box or choke

the flow line valve For high rate wells the flow tee is often Y-shaped to reduce turbulence and erosion. Similarly, a flow control valve may be installed in a straight run rather than in the conventional right-angled bean arrangements. A second side outlet is often used on high pressure wells as a connection for a tubing kill line. Similarly, two master valves are often used in severe operating conditions. This is often a regulatory requirement in sour or high pressure wells.

Tubing Size

Rating

Tree Bore

Tree Drift

(in)

(mm)

(psi)

(MPa)

(in)

(mm)

(in)

(mm)

2 3/8

(60)

15,000

(103)

2 1/16

(52)

1.901

(48)

2 7/8

(73)

15,000

(103)

2 9/16

(65)

2.347

(60)

3 1/2

(89)

5,000

(34.4)

3 1/8

(79)

2.867

(73)

3 1/2

(89)

15,000

(103)

3 1/16

(78)

2.867

(73)

Table 1: Christmas tree specifications Full opening gate valves are used for the master and swab valves ( Figure 2 ,

Figure 2

Manually-operated gate valve, Figure 3 ,

Figure 3

Pressure-actuated gate valve in open position, and Figure 4 , Pressure-actuated gate valve in closed position).

Figure 4

These should not be opened when a significant differential pressure exists across the closed valve. The throughbore of the tree is specified by the API and is generally 1/16 in. larger than the tubing ID to facilitate installation of a back pressure valve in the tubing hanger. Tree sizes are shown in Table 1. Although the body of a Christmas tree is normally pressure tested to twice the working pressure for trees rated at 5000 psi (34.4 MPa) and less, and 1.5 times the working pressure for 7500 to 20,000 psi (52 to 140 MPa) ratings, the flange bolts and valves may not necessarily have the same rating. Therefore, it is extremely imprudent to overload Christmas trees when stimulating a well. Similarly, many valves are unidirectional and this should be taken into account when planning pressure test sequences. Valve gates can be damaged by applying significant pressure from the wrong side. Beans and Chokes In flowing wells, rate is controlled by a bean, choke, or flow control valve. Traditionally, the most common was the fixed bean operating under critical flow

conditions (i.e., at sonic velocity). Under these conditions the upstream pressure, or tubing head pressure (THP) , is independent of the downstream pressure, or flow line pressure (FLP). To achieve this, THP must be greater than or equal to 2.0 times the flow line pressure. The advantages of operating under these conditions include the following: · over the short term (generally one to three months) the well rate is fixed, and a single monthly test is representative of the entire producing period · test separator conditions need not be the same as the bulk separator to ensure a representative test, since fluctuations in downstream pressure do not affect THP at sonic velocity · well flow rate is limited in event of a line break · lower pressure ratings can be used for flow lines and separators · the sand face is not subjected to production surges in event of a production facility fluctuation (this point is particularly important in weak formations) · choke performance can be used as an indication of production rate The disadvantages relate primarily to lower pressure wells and gas wells: · the choke introduces a major pressure loss into the system · flow lines may need to be larger to accommodate the higher flow velocities without excessive erosion or pressure loss · associated cooling can cause hydrate formation at the choke · choke beans are inconvenient for changing production rates in accordance with changes in gas sales requirements To meet the last objection, motorized or manual variable chokes or flow control valves are often used on key wells so that the operator can quickly change the field flow rate.