Buckling

In wells with a long inclined or horizontal segment, drag can become a problem. To keep the weight on bit (WOB) additional axial compression is used. When sufficiently high levels of axial compression are imposed on a drill string it will buckle in a sinusoidal fashion. A further increase in axial tension will lead to helical buckling where the drill string will spiral in the well bore and reach a helical configuration with a massive increase in drag, and possible lock up as result⁽¹²⁾.

The pipe starts to buckle in a sinusoidal fashion at the critical buckling force^(13,14,15): _B> 2EFG5_B

21 5_B= Wall side force per unit length(N/m)

_B= 0K -

The “EI” term is a measure of the pipe stiffness, it’s resistance to bending. The Young’s modulus is material specific, while the area moment of inertia depends on material crossection and shape. For a pipe, I is found through the formula:

G = "

64 (N^#O− N^O) N_# =

N =

The wall side force is calculated from this formula⁽¹⁵⁾:

5_B = 2(P(5? (Q) + _?Q^I)^$+ (_? QR^I)^$

5_? = S 4 -ℎ of pipe

Q = 40 . _? =buckling force

R = 40 . T ℎ

-′ ℎ ! ! 4 ℎ ℎ

If sinusoidal buckling has occurred and more axial compression is added the pipe will eventually buckle in a helical fashion. For the Wellplan simulator the onset of helical buckling is set at 2,8 times the force of sinusoidal buckling, and although there are some disagreement over what formulas or values are to be used, because of the limited understanding of the buckling phenomenon this is a common value in the industry^(14,15,20).

22

Figure 5: Illustration of sinusoidal buckling and helical buckling⁽¹⁵⁾

Sinusoidal buckling generates an addition to drag forces but is usually tolerable, while the additional side force generated from helical buckling is much larger and quickly leads to lock-up and a stop in drilling.

The critical buckling force depends on modulus of elasticity, the area moment of inertia, and wall side force. A lighter material than steel will give smaller wall side forces than steel, but if that material is more elastic than steel it could still give a smaller critical buckling load for the same pipe crossectional area.

Manufacturing the pipe with larger OD and the same wall thickness would provide additional buckling resistance, however this will increase annular pressure losses, and much more than the decrease in pressure losses inside the string as a result of the increased ID.

23 2.2 Fundamentals of hydraulic performance

To obtain good hole cleaning, high mud rates are important in order to agitate cuttings in the well bore and to keep them in suspension. The mud pumps apply an initial pressure to the mud at the top of the string, but this pressure diminishes along the inside of the string until the bit is reached due to frictional pressure loss. More pressure is then lost when crossing the nozzles in the bit and then pressure is lost due to friction in the annulus all the way to the surface.

While frictional pressure loss is not desired inside the string, it is essential for proper bit cooling, lubrication and cleaning. Frictional pressure loss is essential in annulus hole cleaning to suspend and remove cuttings.

The frictional pressure loss in a well increase with length and the additional pressure needed is supplied by the mud pumps. However there are limits to what pressure the pumps can deliver, and also to what differential pressure the drill pipe can withstand. An increase in applied pressure from the pumps will also lead to increased pressure loss in the string and over the bit, so that the annulus will get a smaller increase in pressure than the difference in initial and extra pressure applied from the pumps. To large pressure loss over the bit is also not desirable as it could lead to lower ROP and poorer bit cleaning.

To calculate frictional pressure loss the flow regime has to be determined through use of the Reynolds number^(16,17). The formula is valid both for inside the pipe and for the annulus, although the formula for hydraulic diameter differs.

24

If the Reynolds number is smaller than 2000 the flow is regarded as laminar, between 2000 and 4000 intermediate and if the Reynolds number is larger than 4000 the flow is regarded as turbulent^(16,17). These are however not absolute values, and variation is to be expected.

In laminar flow, fluid flows in parallel layers with no disruption between the layers. Each layer moves parallel to the adjacent one without mixing.

With rising Reynolds numbers eddies and vortexes and other instabilities come into existence. Originally these instabilities originate from the wall of the pipe, but these near wall instabilities will disturb flow in the other layers in turn and cause more turbulence.

The importance of turbulence in pressure loss calculations stems from the greatly increased friction and frictional pressure loss in a pipe with turbulent flow compared to laminar flow.

For calculating pressure losses there are different formula for laminar or turbulent flow, and for string or annulus. Also, these formula depend upon whether the fluid is Newtonian (constant viscosity), or non-Newtonian (flow rate shear dependent viscosity). There are several different mathematical models describing non-Newtonian fluid behavior, but all of these are approximations, even for steady state flow. One of the models commonly used by the oil industry is the Bingham plastic model, which also is the simplest of the non-Newtonian flow models. The formulas used in this model for friction pressure

25 drops in both pipes and annuli are given in the drilling data handbook, and are shown in the table below⁽¹⁸⁾.

Table 1: Pressure loss equations from drilling data handbook⁽¹⁸⁾

∆ = ( = -ℎ 40 = ! __# = = !

These formulas are valid for Bingham fluids and the calculations in chapter 2.2.1 and 3.3 are based on these formulas. The simulations used for T&D and buckling are also based on the Bingham plastic fluid model.

The string has to be divided into segments for calculations as there are differing well outer diameters along the length of the wellbore such as in the cased and open hole sections.

2.2.1 Diameter

The inner diameter (ID) is critical for hydraulic performance, since it is both important in determining Reynolds number and therefore flow regime, and the frictional pressure loss in the pipe. It is also one of the factors that vary between the different drill pipe alternatives.

For determination of flow regime there exists a linear relation between flow cross sectional diameter D and Reynolds number Re, as seen from the equation of Re.

For the friction pressure loss equations there is a non-linear relationship between hydraulic diameter and pressure losses where there is a large increase in pressure losses when the hydraulic diameter nears zero. For laminar flow pressure loss increases with 1/D⁴, while for turbulent flow it increases almost with 1/D⁵. For complete turbulent flow it increases with 1/D⁵, but it is usually assumed that the turbulent

26 flow is not fully developed. The standard assumption in the Drilling Data Handbook is that pressure loss increases with 1/D^4.8 as diameter decreases.

The values used in figure 7 and 8, are taken from the preliminary mud design to be used at the Skrugard field, and the rate of 2000 l/min is taken from reviewing offshore drilling reports and represents a number somewhere between high and low rates.

Figure 6: Pressure loss inside drillstring vs. inner diameter of drill string for a 1000 m well with Q=2000l/min, µp=20 cP, and 1,22 kg/l

Pressure loss in drill string vs. drill string ID

Laminar Turbulent

27

Figure 7: Pressure loss in annulus vs. annulus crossectional diameter for a 1000 m well, m well with Q=2000l/min, µp=20 cP, and 1,22 kg/l

2.2.2 Equivalent circulating density (ECD)

ECD is the effective pressure exerted by a fluid on the formation while circulating, but converted to density. ECD is calculated by adding the density of the fluid and the annular frictional pressure loss converted to density. ECD is useful to avoid too large pressure fluctuations in pressure sensitive formations.

While mud density can be within the fracture gradient for the formation, the ECD can be over the gradient and the fluid pressure can then fracture the formation, leading to potential losses and/or kicks.

ECD is usually calculated through the formula:

FgN = ∆Y_hii

- ∗ <N + ^;9:

∆Y_hii= ()

<N = < ! ℎ _;9:= (K-/^b)

ECD can also be expressed as density compared to water (s.g.) 1

Annulus hydraulic crossectional diameter [inch]

Pressure loss in annulus vs annulus hydraulic diameter

Laminar Turbulent

28 As can be seen from the formula ECD is directly affected by annular pressure loss, which is affected both by annular crossectional diameter and well length. Increasing well length, or decreasing annular

crossectional area will directly impact annular pressure loss and therefore ECD.

Table 2: ECD as a function of string OD

2.3 Wear

Abrasive wear is a result of drill pipe contact with borehole/casing wall.

Wear rates are dependent on:

- surface hardness of the pipe material - friction

- sliding distance

- rock abrasive properties - pressing against formation force

- lubricating properties of drilling fluid⁽²¹⁾.

- With differing materials there will be different pressing against formation force, and surface hardness, resulting in less wear for the lighter and harder materials.

1 10 100 1000

8,2 7,9 7,6 7,3 7 6,7 6,4 6,1 5,8 5,5 5,2 4,9 4,6 4,3 4 3,7 3,4 3,1 2,8

ECD in sg

String OD [inch]

29 Excessive drill pipe wear could lead to loss of pressure integrity, possible leakage, or twist off of the string.

Casing wear may also be a problem in long wells, as it may result I loss of pressure integrity and possible leakage.

Casing wear depends on:

- Wear when installing the casing

- Surface roughness and material of the drill string - Pipe pressing against casing force

- Hardness of the drill string material - Lubricating properties of the dilling fluid

2.3.1 Surface hardness

The surface hardness of drill pipe depends on material and treatment of the material. Steel can for example come in many hardness grades dependent on hardening or tempering, and increased hardness often gives reduced ductility and toughness. Hardened steel often have increased hardness, tensile strength and yield strength, and lower ductility and toughness.

There are several hardness scales in use, with the Rockwell C scale often used for steel, and the brinell scale frequently used for less hard materials such as aluminum.

When converted from Rockwell C S-135 steel is about 270 BH on the brinell scale, which is about twice as hard as aluminum for example, which is typically 120-140 HB^(9,38).

Surface hardness is essential in wear, as harder surface will result in substantially less wear when drilling, if all other factors are the same.

2.4 Fatigue

Material fatigue is a failure experienced by materials that undergo cyclic loading stresses. The material failure occurs at much lower stresses than the material tensile/yield strength because of the cyclic loading. Fatigue behavior is usually described in a S-N diagram with stress amplitude (S) and number of cycles (N) at the two axis.

Fatigue can be a problem in drilling because of bending and rotating simultaneously in curved regions of the well path. If the stresses experienced are large enough fatigue accumulates with every revolution of the string⁽²⁾.

30

3. Alternative materials for drill pipe

It is important to point out that, since the field used in this thesis is about to be developed, the alternative pipe materials presented is based on what is presently available for drilling. Aluminum, titanium, and high strength steel is under production and easily available in the short term. Composite pipe needs to be designed for the specific application, and produced in large quanta. With the

timeframe of several years before the drilling campaign in the Skrugard area it should be available for drilling.

A summary table of the material properties compared to S-135 steel will be presented at the end of this chapter. The properties for aluminum used for calculations in the whole chapter 3 are obtained through Alcoa Oil&gas^(29,30). Titanium values are obtained from titaniumengineers⁽³¹⁾, CDP values are obtained from ACPT Inc⁽⁴⁷⁾ and for high strength steel trough Grant Prideco⁽⁴⁵⁾.

The CDP pipe can be manufactured to meet many requirements by adjusting the angle of the fibre weaving. With more axially oriented fibers, the tension yield strength will increase, while orienting the fibers less axially will give torsional strength, and higher pressure rating. For the calculations in this chapter, the properties of the CDP from the Statoil report is used⁽⁴⁷⁾.

Drill pipe dimensions available for the different alternative materials available differ. This is because some materials rely on thicker walls to achieve the necessary stiffness, yield strength, and/or other qualities. The tool joints are the same for all the alternatives, and this is realistic because all the alternative drill pipe materials are manufactured with steel tool joints.

Material S-135 TDP ADP UD-165 CDP

Table 3 - Drill pipe and tool joint dimensions for the different drill pipe alternative materials

31 3.1 Use in the field

3.1.1 Aluminum DP

Aluminum has been used for drilling wells for decades, mostly in Russia and the former Soviet Union, where aluminum alloy drill pipe (ADP) is, and has been since the 50’s, commonly used^(24,25). In the 1980’s ADP averaged about 80% of all drill pipe in operation in the soviet union⁽²¹⁾.

3.1.2 Titanium DP

TDP has been manufactured and used on a limited scale for ultra-short radius drilling (USR), but because of the high cost (7-10 times that of steel) it has seen limited use in drilling. Because of qualities like low density, high strength, flexibility and superior corrosion resistance, titanium is very suitable for

drilling⁽²⁶⁾.

3.1.3 Composite DP

In 1998 the U.S. Department of energy funded a three year program to develop and qualify CDP. Today both 3⁵_k8 and 6 inch OD CDP is available for use in drilling, but is not widely adopted by the industry⁽²⁷⁾. This is probably because SDP is usually sufficient for drilling and CDP is more expensive and less known in the industry. Like the other alternatives CDP has strengths and weaknesses that makes it potentially useful in drilling some wells, while it will be a bad alternative for drilling other wells.

3.1.4 High strength steel DP

Over the last years high strenght steels like Z-140, V-150 and UD-165 has been developed, with much higher yield strength than ordinary S-135. The Z-140, V-150 and UD-165 is not yet been adopted by API but as can be seen from figure 9 both Z-140 and V-150 has been sold and used extensively for over ten years now, while UD-165 is a relatively new product and has just been sold for a few years ⁽²⁸⁾.

32

Figure 8: Cumulative sales of high strength steel DP in feet⁽²⁸⁾

3.2 Torque and drag

3.2.1 Aluminum drill pipe

ADP offers greatly reduced drag and torque in drilling, as an effect of the light weight. Aluminum alloys are typically about a third of the weight of their steel counterparts, so even with the added weight of steel tools joints 5,68 inch ADP weights 55% of the conventional 5,5” SDP counterpart, when submerged in mud the ADP also benefits from greater buoyancy than SDP, further reducing weight compared to S-135 SDP to 44% in a 1,22 sg. mud.

The yield strength of the strongest aluminum alloy used in DP is 69 ksi, and about half of the 135 ksi of S-135 SDP⁽⁵⁾. Aluminum is also more sensitive to increased temperature than steel and, the yield strength of aluminum can be further reduced by temperatures above 250^oF⁽²⁷⁾.

The STWR for aluminum is 15% higher than for S-135 DP submerged in 1,22 sg. mud.

With under half of the buoyed weight of S-135 DP there will be a large decrease in friction and torque and drag. The low weight and high strength to weight ratio means that ADP will be able to drill longer wells as long as torque and drag is the limiting factor.

33 The low Young’s modulus of aluminum (35% of S-135) makes ADP susceptible to buckling and this can severely limit the length possible to drill, especially in wells with high doglegs. The added wall thickness partially offset the lower Young’s modulus, but pipe stiffness is in total half (50%) of S-135 stiffness making buckling a concern. ADP light weight will reduce drag forces somewhat, and this should help in preventing buckling

3.2.2 Titanium drill pipe

TDP (6246 alloy) typically has a density of 4,65 g/cm³ which is about 59% that of S-135 steel. With tool joints of steel the weight is 70% of S-135 pipe, and adding buoyancy the difference increases to 63% for 5,5” OD TDP submerged in 1,22 sg mud.

TDP has a very high YS of 135 ksi, which equals the 135 ksi YS of S-135. The lower density of titanium gives a remarkable strength to weight ratio of 163% of S-135 STWR.

The reduction in weight translates directly into a large reduction in normal force and friction, and hence torque and drag, for a horizontal section. When accompanied with increased YS compared to S-135 any use of TDP will give the opportunity to drill longer wells.

TDP like ADP has a lower Young’s modulus than S-135 SDP. While higher than the Young’s modulus of ADP it is still only 55% of the S-135 Young’s modulus. This severely impacts pipe stiffness and even with the thicker walls the total stiffness is 71 % of S-135 making buckling a concern. The lower weight will also help to reduce drag and this will help in preventing buckling.

3.2.3 Composite drill pipe

Like TDP and ADP the reduced weight of CDP will give reduced drag. In air CDP weighs only 43% of S-135 DP. This extreme difference is only increased submerged in mud, where the weight of CDP is only 29% of the S-135 weight.

CDP has relatively low YS, but as the weight is so much lower than the weight of S-135, CDP still has a STWR that is 15% higher than for S-135.

CDP has a very low young’s modulus of just 16% of the S-135 Young’s modulus. Despite the light weight, it is therefore very susceptible to buckling. This is somewhat compensated for by both increasing wall thickness and OD compared to S-135, but the resulting stiffness is still only 28% of S-135 stiffness. The light weight will also to some degree compensate for the low stiffness as the drag forces will be lower.

34 3.2.4 High strength steel drill pipe

The density of UD-165 is the same as for S-135 making these two steels the same weight for the same volume. Downscaling the pipe wall reduces the volume of the metal, but also decreases the buoyancy of the pipe. In air the weight of a UD-165 pipe is 80% of a S-135 pipe. Because of a very small difference in density the buoyed weight is still 80% of S-135 in a 1,22 sg mud.

UD-165 has a YS of 165 ksi which is 22% higher than the YS of S-135, making it the material with the highest YS of the alternative drill pipe materials. The combination of lower weight and higher YS gives a excellent STWR that is 52% higher than STWR for S-135, and UD-165 pipe is only bested by TDP in STWR.

The lighter weight of the UD-165 alternative should help to reduce torque and drag and help to extend well length if torque and drag are limiting factors.

Young’s modulus for S-135 and 165 is the same, but since the cross sectional area is different, UD-165 has 19% less stiffness than the S-135 alternative. This of course means that UD-UD-165 is more susceptible to buckling than S-135 DP.

UD-165 DP could be produced with the same dimensions as ordinary S-135, and would then have the same stiffness, and the same buckling resistance. The UD-165 pipe would in this case also have the same

UD-165 DP could be produced with the same dimensions as ordinary S-135, and would then have the same stiffness, and the same buckling resistance. The UD-165 pipe would in this case also have the same

In document The use of alternative materials for drill pipe to extend drilling reach in shallow reservoirs (sider 20-0)