Wellbore Stability Training

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TABLE OF CONTENTS 1.0 OVERBURDEN DRILLING .....................................................................3 1.1 Borehole Stability........................................................................4 1.2 ECD and it’s Contribution to Wellbore Instability..........................12 2.0 ECD MANAGEMENT AND HOLE CLEANING.........................................12 2.1 Drilling Optimisation Engineers...................................................12 2.2 Downhole Pressure Subs Measurement.......................................13 2.3 Good hole cleaning practices......................................................15 2.4 Hole Cleaning Theory.................................................................17 2.1 Factors Affecting ECD.................................................................17 2.2 ECD finger printing (MWD Pressure Response Testing).................23 2.3 Hole cleaning Plots.....................................................................25 3.0

2.4 Example of Poor Drilling Practices...............................................26 GAS ISSUES..............................................................................30 3.1 Shallow Gas..............................................................................30 3.2 Recent Experience when Drilling 16” Hole Section on Valhall:.......30

4.0 5.0

3.3 Gas Cloud..................................................................................31 BALLOONING..............................................................................33 CAVINGS ....................................................................................33

6.0

5.1 Cavings analysis ......................................................................34 FAULTS.....................................................................................38

7.0 8.0

6.1 Guideline For Problematic Faults .........................................38 WASTE DOMAINS........................................................................39 DRILLING PRACTICES...................................................................42 8.1 Drilling Practices and Optimisation.............................................42 8.1

Good Drilling Practices...........................................................42

8.2

Flow Rates............................................................................42

8.3

Connection Procedure............................................................42

8.4 Tripping...................................................................................46 8.5 Running Liners - WIP 9-5/8” Liner Running and Cementing Operations......................................................................................50

9.0

8.6

Limestone Stringers...............................................................52

8.7

Torque and Drag.....................................................................53

8.8 Cycling Pumps...........................................................................54 LOST CIRCULATION.....................................................................55 9.1

10.0

LCM Decision Tree for Valhall...................................................56 STUCK PIPE..........................................................................58

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CEMENT BLOCKS......................................................................59 Cement-blocks falling on top of BHA /stabilizers..............59

11.2 Cement Blocks in the rathole....................................................60

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OVERBURDEN DRILLING

Overview ·Drilling wells at Valhall is often like ”walking the razors edge” ·Drilling practices that works well in other fields (even Ekofisk) will result in well problems ·Number of trips should be kept to a minimum (drill, trip, run casing) ·Tripping procedures are critical (there are no short cuts) ·Keep the hole clean as you drill (ROP is high) ·Minimize surge/swab, temperature fluctuations and mechanical destabilization of wellbore during drilling to increase chance of success during trip out Drilling the overburden section from 370m to the top Tor reservoir on Valhall has become increasingly difficult. Subsidence of the seabed of up to 4m and up to 1m at the reservoir has also increased the difficulty. The formation is generally weak and drilling practices established for Valhall should be closely followed to minimise any damage to the borehole.

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1.1

Borehole Stability

1.1.1

Pore, Fracture and Collapse Pressures

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The following figure 1 illustrates the generic pore, fracture and collapse pressures over the Valhall field and associated formation tops against TVD.

Fugure 1 General Pressure Profile for Valhall

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Pore Pressure Pore pressure is the pressure exerted by pore fluids This is the pressure within a formation caused by the fluids within the pore spaces. The pore pressure depends on the weight of the column of water saturating the pores of the sediments between the measurement point and the atmosphere.

P = Density fluid x Vertical Depth x Constant Water density is a function of the concentration of dissolved salts, which is usually expressed as salinity. As formation waters vary greatly in salinity, they also vary in density. Normal pore pressure can vary from 8.34 to 9.0ppg. The pore pressure in the overburden section is over pressured and has an increasing trend towards section TD at around 2470 m TVD. Pressure above estimated matrix pore pressure is expected. 1.1.3

Overburden Pressure and Fracture Pressure & F.I.T.

1.1.3.1 Overburden Pressure Overburden Pressure is the pressure at any point in the formation exerted by the total weight of the overlying sediments. This is a “static load” and is a function of the height of the rock column and the density of the rock column. Since subsurface rocks/formations are not homogenous, to calculate the overburden pressure (S), the rock column must be broken up into relatively homogenous intervals (Dz ). Thus, the incremental over-burden pressure is: where: S = Overburden Pressure (psi) b = Rock/Formation Density (gm/cc) Dz = Depth Interval (feet) The Overburden Gradient (OBG), is the sum of these increments divided by the total depth. Overburden pressures and gradients are used in Fracture Pressure calculations.

1.1.3.2 Fracture Pressure Fracture Pressure is the stress, which must be overcome for hydraulic fracturing to occur. This stress is known as the minimum lateral stress, When fracturing occurs, the fracture orientation will usually be parallel to the greatest stress (which is normally the over-burden pressure), which means the fractures will be vertical. For horizontal fractures to occur, the overburden pressure will have to be exceeded. This will occur in areas of large horizontal tectonic stresses. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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Although there are several methods for estimating fracture pressure, the best way to arrive at an accurate value is to perform a Formation Integrity Test (FIT), or “Leak-Off Test.” Fracture Initiation Pressure: is defined as an applied pressure to equal to, or slightly exceeding the total formation strength. At this pressure the formation will rupture, producing a fracture. Once a formation is fractured the pressure required to open the fracture will be lower and as a result the formation is inherently weaker. Fracture Injection Pressure: is an applied pressure equal to, or slightly exceeding the least horizontal stress and the pore pressure. The pressure is sufficient to hold open and propagate a pre- existing formation and will always be less than the fracture initiation pressure. The safe operational ECD window for the 12-¼” x 14” section is derived based on LOT/FIT data from the 13–3/8” casing shoe. Available LOT/FIT points at Valhall for the 13-3/8” shoe depth is given in the figure below. A point to note in the diagram above is that fracture pressures do not follow the pore pressure trend and increase with depth. This is not typical and illustrates the inherent weakness in the Overburden formation due to faulting and fracturing. 13 3/8" casing - LOP vs. TVD LOP (ppg) 8

9

10

11

12

13

14

15

16

17

18

1000 1050 1100 1150 TV 1200 D (m RK 1250 B) 1300 1350 1400 1450 1500

Figure 2 Plot of available LOT/FIT tests around the 13–3/8” shoe at Valhall. In order to minimize risk of losses in faults and destabilization of blocky cavings in faults and natural fractured intervals, the maximum ECD should be held at or below 15.0 ppg for the 14” hole section.

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Tests for determining formation strength – Figure 3

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1.1.3.3 Collapse Pressure Collapse pressure represents the minimum mud weight required to maintain a gun barrel hole and keep the formation “intact” before potential collapse. The small difference between pore pressure and collapse pressure on the Valhall field is very unusual. Much greater collapse pressures can usually be expected. The collapse pressure as illustrated in figure 3 gives an indication of the mud weight required to help generate a gun barrel hole. Mud weights below this will initiate cavings and over the longer term, formation collapse. Prior to drilling the hole the in situ stress was the overburden pressure. After drilling there are two stresses acting on the borehole, overburden and hydrostatic pressure. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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Figure 4 Insitu stress A fine balance exists to maintain borehole stability; too higher mud weight (ECD) could cause fracturing and subsequent losses or borehole collapses. If mud weight in insufficient Breakouts can occur and borehole collapse. ( see figure 4 below)

Figure 6 Mud weight and borehole stability

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A further complication to borehole stability is hole inclination. As inclination increase to horizontal the safe margin between collapse and fracture decreases.

Figure 6 Effect of Inclination on mud weight range for bore hole stability As can be seen from the above figure 5 the mud weight for a stable well decreases as the hole inclination increases. The mud weight range between preventing borehole collapse and fracturing is narrow.

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Equivalent Mud Weight (PPG)

Depth (m TVD RKB)

7

8

9 10 11 12 13 14 15 16 17

400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600

Matrix Pore Pressure (PPG) Mud Weight for No Breakouts (PPG) Frac Gradient (PPG) Recommended Mud Weight (PPG)

Figure 7

Figure 6 shows the recommended mud weight to drill the overburden on Valhall and the mud weight required to prevent breakouts (collapse). The margin is very narrow between collapse and fracture. The above diagram also indicates the importance of hole cleaning to keep ECD below 15.0 ppg and the importance of good drilling practices to prevent any pressure spikes, which could cause fracturing of the formation.

1.1.4

Hole Stability - Drilling Mud Weight A mud weight in the 14.6-15.0 ppg is necessary to control the overburden. A static mud weight of 14.6 ppg is recommended as long as no other signs of instability are observed. This static mud weight will provide a safe ECD window below 15.0 ppg while drilling an oversized hole (14”) and below 15.3 ppg while drilling the 12 ¼”. 15.3 ppg was believed to be the upper safe ECD value over long time exposure for wells at Valhall. However, to stay well below this limit and provide a margin for error the ECD for this well will be kept as low as possible. It is considered likely that the upper safe ECD limit is decreasing with time as the Valhall field becomes increasingly unstable in terms of wellbore integrity over time. The lower static mud weight of 14.6 should be sufficient to produce none at all or limited amounts of shear induced cavings with this wellbore inclination Please note: • Drill the section with a mud weight of 14.6 ppg as long as no other signs of instability is observed. • Limit the ECD fluctuation to between 14.6 and 15.0 ppg for this hole section.

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• We do not expect to see larger volumes of shear induced cavings or bedding parallel failed cavings, if we do we need to ensure the hole cleaning is OK. If we have problems cleaning the hole for shear induced cavings, we can weigh up • We could observe sporadic blocky cavings when drilling through the fault zones. • We could expect splintery cavings when drilling into the “gas interval” below the 13 3/8” shoe.

1.2

ECD and it’s Contribution to Wellbore Instability

1.2.1

ECD – Effective Circulating density The circulating fluid causes pressure losses to occur throughout the annulus. Pressure losses are dependent on velocity changes (going from one annular section to another) and the annular dimension changes (the length of the annular section). The net pressure loss throughout the annulus is the sum of the pressure losses in the annular sections. This annular pressure represents a net “back pressure,” in addition to the “normal” hydrostatic pressure of the column of drilling fluid. This is known as the “Equivalent Circulating Density” (E.C.D.) or “Bottom Hole Circulating Pressure” (B.H.C.P.). Hp = MW x 0.519 x TVD B.H.C.P.psi = ∑Pin + Hp E.C.D. ppg =

B.H.C.P.__ 0.0519 X TVD

High annular pressure losses result in a decrease in the bit's hydraulic horsepower, or a decrease in the cleaning capacity of the bit. High E.C.D.s result in lower drill rates, possible fracturing of formations and poor bottom hole cleaning.

2.0 ECD MANAGEMENT AND HOLE CLEANING

2.1

Drilling Optimisation Engineers Primary role of the DOE is to assist and advise on successful drilling and liner operations in the overburden with a focus on ECD management and well bore stability In co-operation with BP, Baker Hughes introduced a small specialist team of Drilling Optimisation Engineers (DOEs) to assist in satisfying the hole section objectives. The

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knowledge acquired by these engineers has come from the study of Valhall wells, the use of MWD pressure sub data and the adoption of different drilling practices developed by the DOEs and BP. Valhall experience has shown that ECD management and hole cleaning have been critical to this task.

2.2

Downhole Pressure Subs Measurement

The introduction of pressure subs as part of the MWD tool suite has been instrumental in the closer study of the effects on mud weight of depth and pressure and the influence that different mud systems have on ECD. The PWD subs measure annular pressure and often, internal collar pressure. This data is transmitted to surface and plotted real time as an equivalent mud weight (ECD). Data is also stored in memory at a higher frequency. The tools can be set up to record memory data so that analysis of swab and surge pressures can be made while tripping in or out.

Figure 8 MWD pressure Sub

ECD data frequency should be optimised for each run depending on run length, expected ROP, tool memory capacity and formation evaluation data requirements. For the initial run high data frequency while testing and drilling ahead will benefit future analysis as the effects of the recommendations to minimise pressure peaks can be evaluated.

In previous wells the MWD pressure sub has given not only real-time circulatory ECD measurements, but also the maximum and minimum ECD values during pump off events. These values have proven important, giving both the static mud weight and the ECD when resuming pumping after a pump off event. Figure 9

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2/8 F-3A T3 COMPARISON PUMPS OFF ECD DATA VS MUD WEIGHT 15.30 15.20 15.10

MWT Min ECD Max ECD

ppg

15.00 14.90 14.80 14.70 14.60 14.50 14.40 14.30

DEPTH metres

From previous Valhall wells with oil based mud systems with a density in the range off 14 – 15 ppg, the mud weight at the bottom of the hole had a density of typically 0.1 ppg less than surface measurement. Rapid turnaround of ECD memory data is required to enable it to be used for the optimising of the following trip in or out. So that the optimal frequency and time required when staging in the hole can be estimated. Down hole Pressure Subs provide: Improved Drilling Efficiencies Safer Operation of the drilling process Reduced incidences of stuck pipe Better Understanding of actual against theoretical pressures Cuttings annulus loading Fracture avoidance Kick Detection Running Speed monitored for swab and surge Leak off test monitoring Mud properties monitoring Future Field Development planning.

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Good hole cleaning practices.

1. Clean hole as fast as it is drilled. Use the curves in this section to match hole cleaning to instantaneous penetration rate. 2. Ensure mud is within specification. Rheology is very important for hole cleaning. Redefine the specification if the mud properties are obviously inadequate for the hole section. 3. Circulate clean prior to tripping. Bottoms-up does not ensure a clean hole. Use the circulation guideline. Always check the shakers are clean before tripping. 4. Reciprocate and rotate the pipe continuously while circulating. Motion disturbs cutting beds down hole. Only rotate slowly unless it is possible to reciprocate, otherwise ledges/key-seats may form. 5. Plan and perform the wiper trips as hole condition dictate. Wiper trips help disturb cutting beds further up the hole. 6. Monitor the shakers. Both volume and type of cuttings are important indicators of hole condition. Know what to look for. 7. Keep all circulation and solids control equipment in good working order. Subject to hole condition stop, pull back to inside the casing shoe, and repair vital equipment (esp. pumps) rather than drilling ahead with insufficient hole cleaning capability. . Hole cleaning calculations. Calculate hole cleaning for the section with the highest inclination. All other sections will clean if this section cleans. The most difficult angle to clean is 50-60 degr. Angles above this present no greater difficulty. Vertical wells: Clean vertical wells, with high yield-point, viscous mud. Large diameter holes especially, cannot be cleaned by velocity alone. Use high viscosity sweeps for additional hole cleaning. If muddedup, maintain effective gel strength for cutting suspension. Flow rate should be increased with hole angle: a 30 degr. Inclined well requires 20% higher velocity than an equivalent vertical well for effective cleaning: a 60 degr, inclined well requires about twice the annular velocity of a vertical well. Deviated wells: Clean inclined wells, with high velocity. Use lower viscosity mud to induce turbulence to help clean high angle and horizontal holes. Rotation and reciprocation are critical to good hole cleaning as the inclination exceeds 45 degr. Hole cleaning optimization: Hole cleaning and penetration rates can be optimized with the use of pressure subs 1. Increasing the flow rate allows the hole to be cleaned faster. 2. Increasing the transport index increases the ability of the mud to clean the hole. The transport index can be increased by: • Increasing the mud weight. • Increasing the rheology factor (i.e. Increasing the PV or YP) Remember: Increasing any of the above parameters will affect the others. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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Circulation prior to tripping: Circulating time is dependant on hole size and inclination. The following method calculates the optimum circulation prior to tripping. Note: The following guideline is only applicable if the hole has been properly cleaned while drilling. If the shakers are still loaded after the calculated time, keep circulating until the shakers are clean. Inclination of well (degrees) 0-10 10-30 30-60 60-90

Section length factor 17 1/2" 1.5 1.7 2.5 3.0

12 1/4" 1.3 1.4 1.8 2.0

8 1/2" 1.3 1.4 1.6 1.7

6" 1.3 1.4 1.5 1.6

To calculate circulation volume: 1. Divide well into sections as per the inclination intervals in the above table. 2. For each section multiply its length by the appropriate section length factor from the table to obtain an effective length. 3. Number of circulations= Total effective length Measured depth 4. Volume required = (no of circulation’s x bottoms up

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Hole Cleaning Theory

Hole cleaning simulations have been conducted using the Advantage hydraulics model. The hole cleaning model for high angled wells has been developed by BP. This model is currently being incorporated within Well Plan. It is a physically based model that has been developed from full scale flow loop testing and mathematical modeling. Results from the model have been validated with field data from many of BP’s worldwide extended-reach wells.

D ra g F o rc e

L ift F o r c e

H o le A n g le

F r ic

tio

n

F o rc e

G r a v ity F o rc e

Figure 10: Forces Acting on a Cuttings Bed The basis of the model assumes that a cuttings bed will be formed on the low side of the wellbore. Cuttings on a high inclination well have significantly less time to reach the low side of the hole under the effect of gravity and cuttings beds will form. • • •

35 – 45 degrees hole angle - cuttings beds form 45 – 65 degrees hole angle - avalanching may occur 65 – 90 degrees hole angle - stable cuttings beds. Increasing the flow rate alone will not remove them. Requires additional mechanical agitation. e.g.string rpm (minimum 60 rpm)

Cuttings can then be removed by either the drag force acting to move the cuttings upwards or the lift force acting to move the cuttings into the main flow stream above the settled bed (see Figure 1.) The drag force dominates in laminar flow (high viscosity fluid), whereas the lift force dominates in turbulent flow (low viscosity fluid). Therefore a high angle well can be cleaned effectively with either a low viscosity fluid or a high viscosity fluid. Fluids of intermediate viscosity result in transitional flow, which is less favourable with respect to cuttings transport.

2.1

Factors Affecting ECD

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The following can indirectly or directly effect the ECD: • • • • • • • • • •

2.1.1

Flow Rate String rpm PV and YP Accuracy of surface Measuring Equipment Temperature and Pressure downhole Surface solids control equipment Formation of cuttings beds/disturbance of cuttings beds (45 – 55deg) Borehole instability problems Pills / Sweeps in the system Mud Weight

Effect of Rheology on Hole Cleaning and ECD

Figure 11 shows the influence of mud Yield Point (YP) on the minimum flow rate required for good hole cleaning. Results show that the flow rate initially increases as the mud YP is increased and then falls off again at YP > 15 lb/100 ft2. This represents the transition from turbulent to laminar flow as the mud viscosity increases. Figure 2 also shows the ECD (Equivalent Circulating Density) calculated at the section total depth for a 14.8 ppg mud. The ECD values are based on the calculated minimum flow rate required to clean the hole. 950

15.8 15.7 15.6

Flow Rate

850

15.5 15.4

800

15.3 750

15.2

ECD (14.8 ppg mud)

700

ECD (ppg)

Minimum Flow rate (gpm)

900

15.1 15

650

14.9

600

14.8 10

15

20

25

30

35

40

Yield Point (lb/100 sq ft)

Figure 11: The Influence of Rheology on Hole Cleaning and ECD As the mud YP is increased, the ECD continues to increase despite the reduction in mud flow rate. Thus for regions where the pore pressure/fracture gradient window is narrow, a thin mud may be /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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preferable. However using a thin mud does increase the potential for barite sag. Under these conditions is recommended that a viscous mud with YP in the range 20 - 25 lb/100 ft2 is used. The more viscous mud is advantageous with respect to mud stability (reduced barite sag) and also provides additional resistance against cuttings beds avalanche when the pumps are shut down. The remaining simulations for the 13 ½” section are based on a mud rheology of PV/YP = 46/22 (as used on F16). Based on the simulations a minimum flow rate in the range 750 - 800 gpm will be required to maintain adequate hole cleaning in gauge 13 ½” hole. Typical flow rates used on F16 were in the range 900-950 gpm. Prior to tripping it is important that the well is circulated clean. The BP Amoco guideline for circulation prior to tripping is based on transport efficiencies in the various high angle sections of the well. Details of the technique used can be found in Reference 2. Using this technique the minimum circulation prior to tripping for the F16 profile is 1.7 * Bottoms-Up for the 13 ½” section. Normal circulation rate and rotary should be used throughout this clean-up period. The shakers should be monitored for the volume of cuttings removed. Direct measurement of annular cuttings loading with PWD (Pressure While Drilling) is also very helpful. The use of PWD (Pressure While Drilling) has proved to be very valuable in monitoring hole cleaning efficiency in extended-reach wells. Good use of this technique has been made on the recent Valhall wells.

2.1.2

Influence of Hole Washout on Hole Cleaning

Previous wells drilled on Valhall have experienced hole enlargement in the 13 ½” section. As the hole diameter enlarges, the annular velocity drops off very rapidly and hole cleaning problems can occur. In order to maintain effective cuttings transport the flow rate needs to be increased to compensate for the reduction in annular velocity. This is illustrated in Figure 12 below.

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Minimum Flow Rate (gpm)

1200 1100 1000

ROP = 30 m/h

900 800 700 600 12

13

14

15

16

17

18

Hole Diameter (inches)

Figure 12: Influence of Hole Enlargement on Hole Cleaning The results in Figure 12 show that hole enlargements up to about 15” should still be cleaned with the normal flow rates used on Valhall (900-950 gpm). With hole enlargements beyond 15” the flow rate required for cleaning rises rapidly. In practice it will not be possible to achieve the very high flow rates required to clean the enlarged sections. Every effort should be made to reduce the likelihood and severity of the washout. If significant hole enlargement does occur (>15”), it is recommended that extra time is taken circulating just below the washout prior to tripping out the BHA through the enlarged section.

2.1.3

Effect of Drillpipe Rotation On Hole Cleaning

Rotation of the drillpipe assists cuttings removal in high angle wells. This is modeled in Figure 14. Minimum rotary speeds in the range 100-150 rpm are recommended to assist hole cleaning. At rotary speeds above 150 rpm the increased benefit of drillpipe rotation begins to level off in gauge hole. For out-of-gauge hole, the simulations indicate that increased rotary speed continues to provide benefit at speeds > 150 rpm. In practice the drillpipe rpm may be limited due to concerns of downhole vibration / drillpipe whipping.

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1.84

3500

ECD (g/cc)

3000

String rpm *10

1.83

Flow in (lpm)

2500

Block hight *100 1.82

2000

1500

1.81

1000 1.8 500

Figure 13

1:35

1:30

1:24

1:19

1:13

0 1:08

1.79

Rotational Effects on ECD

1500

Minimum Flow Rate (gpm)

1400

18" Hole

1300 1200 1100 1000

13 1/2" Hole

900 800 700 600 0

20

40

60

80

100

120

140

160

180

Drillpipe rpm

Figure 14: The Influence of Drillpipe Rotation on Hole Cleaning As more data is acquired on the effects of rotation on hole cleaning, the more conclusions are being drawn. The following lessons have been learnt from F-15 and previous wells: 1. Monitoring ECD during periods of high RPM (e.g. at TD of hole section) will give indications of how well the hole is cleaning. The pressure sub indicates the associated increase in ECD as more cuttings are lifted into the annulus by the rotation. 2. Collected data from previous Valhall wells suggests that hole cleaning with a rotary steerable assembly is significantly improved with rotation of 130rpm compared to 100rpm. On F-15 it was possible to drill and clean the 12 ¼” hole with a maximum rotary speed of 100rpm. A contingency option of rotating at 120 rpm was available if hole cleaning was poor and when circulating the hole clean prior to pulling out of hole. Rotation of less than 60 rpm produced /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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little or no beneficial hole cleaning. After periods of drilling with less than 60 rpm, measures to clean the hole should be adopted and treated the same as if orientating with no rotation. The hole angles of greater than 50 degrees accentuated this problem. 3. Rotation must be staged up gradually so as to safely monitor the effects on the ECD and avoid pressure spikes.

2.1.4

Effect of Flow Rate on Hole Cleaning and ECD

Figure 15 shows the predicted ECD at the bit for the 13 ½” section as a function of flow rate. The 2 plots are for Bingham Plastic (PV/YP) and Herschel-Bulkley (Fann data). The Bingham model will tend to over predict the viscosity at low shear rates and hence lead to conservative pressure loss predictions. 15.4 15.35

Bingham Plastic

ECD (ppg)

15.3 15.25 15.2

Hershel-Bulkley

15.15 15.1 700

750

800

850

900

950

1000

Flow Rate (gpm)

Figure 15: Influence of Flow Rate on ECD

2.1.5

Effects of Temperature on ECD

Temperature has a significant effect on ECD values. After tripping in and breaking circulation the cold mud can result in significantly higher ECD, which can be high enough to break down the formation. In order to reduce the negative effect of temperature mud is sheared in the pits to increase the temperature. The use of steam heaters will also be used to warm the mud in the pits. Circulation is broken at intervals while tripping in the hole and if required circulation will be extended to bring the mud temperature up to optimum. Figure 16 shows that with increasing mud temperature there is a corresponding reduction in ECD values. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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95

15,4

90

15,3

85

15,2

80

15,1

75

15,0

70

14,9

65

14,8

60

14,7 marked decreasing trend in ECD

55

14,6

as mud temperature increases 50

14,5

45

14,4

40

14,3 mud losses

35

14,2

TVD (m ) MWD TOOL TEMP (deg C)

PUMPRATE*10 (gal/min)

ECD (ppg)

MW (ppg)

FIG 16 Effects of Temperature on ECD 2.2

ECD finger printing (MWD Pressure Response Testing)

Detailed test procedures to define ECD response to drilling and tripping operations Data can be used for calibration of hydraulics software Suggested Operations for testing: • • • • • • •

Pumps on, also pumps on connection simulation Rotation effect on ECD (clean hole) Rotational effect on cuttings transport Pipe movement and ECD (connection) Mud gelation (cold/warm fluid with/without rotation) Flow check FIT/LOT

Develop clear step-by-step guide for each operation for use at the wellsite High frequency pump off memory data should be recorded for a trip in

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ECD / MW

TEMP / PUMPRATE*10

2/8-F-19, M. Guardian ECD/MW/TEMP/PUMPRATE v TVD

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Record the ECD value transmitted from the tool when pumping at the normal drill rate Maintain flow rate and and start string rotation at low level 50rpm and record ECD Increase string rpm in 25 rpm steps and allow to stabilise and record ECD values Repeat for different flow rates

Figure 17 Showing Detailed MWD pressure response testing Tool configuration is important to ensure correct and adequate data collection When possible, for well integrity concerns, these tests should be performed prior to drilling out the shoe to eliminate the possibility of inducing formation fracture and also the mud should be free of cuttings. However check the proposed operating parameters for RPM against acceptable limits for inside casing. Prior to all testing the mud should be circulated to achieve an even density and stable temperature profile such that the data can be confidently referenced and used to calibrate the hydraulics software.

The data from the tests will be used to build an ECD fingerprint chart, see below. This will help reference the likely ECD response prior to performing operations and can be updated with revised pore and fracture pressure limits and with additional test data as the section is drilled. From this data operating best practices can be refined and the software models updated with actual well data for improved accuracy.

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Fig 18. ECD fingerprinting example Test Programme

1. 2. 3. 4.

Pumps on (breaking circulation) Rotational effects on ECD Pipe reciprocation and ECD Pumps off swab tests – before drill out after drilling ahead and recording data from 2 above 5. Rotational effects on cuttings transport

2.3

Hole cleaning Plots

Mud Volume Tracking Offshore With necessity for mud volume control for hole cleaning, and the well control incidents on F-3AT3, with simultaneous water influx to the annulus and downhole losses, high emphasis is put on mud volume tracking. The mudlogging personnel, under supervision of the DOEs, do this. Both the active volume is monitored as well as the cuttings volumes handled by the MSD (cuttings slurrification). The systems and procedures are now in place for good mud volume tracking. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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Mud volumes are monitored closely and up to date plots are available at all times for accurate monitoring of hole cleaning and mud volumes. Detailed Mud loss AMOCO 2/8-F-15, 12.25" - 13.5" Hole Section 2400,0 2200,0 2000,0

Actual loss Expected loss w/ 0.5 bbl mud per bbl cuttings Expected loss, dry cuttings

Mud loss (bbls)

1800,0 1600,0 1400,0 1200,0 1000,0 800,0 600,0 400,0 200,0 0,0 1700 1900 2100 2300 2500 2700 2900 3100 3300 3500 3700 3900 Depth (mMD RT)

Fig 19 Hole Cleaning Plot

2.4

Example of Poor Drilling Practices

2.4.1

Plot 01 Bad connection Procedures and poor hole cleaning

From the plot it can be seen that incorrect connection procedures are being used, where the flow rate is increased too rapidly. This results in excessive pressure pulses, which could result in fracturing of the formation. An increase in ECD is observed when drilling commences as a result of poor hole cleaning, but no action is taken. Rotary is increased quickly with no staging up, a corresponding increase in ECD is observed as more cuttings are lifted up into the well bore. A pack off results, which could have /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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resulted in borehole failure. Time should be taken to clean the hole, where conditions indicate poor hole cleaning

Plot 1

2.1.1

Plot 02 Poor hole cleaning and too fast pipe movement

Packing off occurs when drilling starts, the rotation was stopped and 10 minutes later drilling resumed with a steering interval. No attempts were made to clean the hole. Increased ECD values are seen at the end of each steering interval and pressure spikes can be observed when short periods of rotation occur. Pressure spikes are also observed due to moving the pipe down too fast.

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Plot 2

2.1.2

Plot 03 No Circulation to establish ECD Trend

Drilling commenced after the pumps were down for 30 mins. It would be prudent to circulate for 10 mins with high string rotation after such an incident to monitor ECD values to see if the hole is clean or if excessive cuttings are being picked up.

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Plot 3

2.1.3

Plot 04 No Attempts to clean hole after numerous pack offs

After tripping in ECD values are 0.3 ppg higher than prior to the trip. No action is taken and the hole packs off when drilling resumes. Packing off continues to be a problem, but after circulation is re-established no effort is made to clean the hole. The pressure spikes generated by packing off have been up to 0.25 ppg, which could result in serious borehole stability problems

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Plot 4

3.0

GAS ISSUES

3.1

Shallow Gas

During the initial batch setting of the 20” casing, two gas stringers were encountered between 384m and 389m RKB while drilling the 26" hole section from Slot 8 (2/8A-l). Thus, 375m is maximum TD of pilot hole. Strict attention must be paid when drilling this interval to be alert for excessive background gas. No gas has been recorded in the shallow sands (from 20” shoe down to ±500m) since F-9 was set in production from this interval. Most gas related incidents (influx) in recent wells have been related to an interval at 1200-1300m TVD in the SE quadrant (wells 2/8-F-1 and F-9) and should not be regarded as shallow gas. 3.2

Recent Experience when Drilling 16” Hole Section on Valhall: On the F-7 well, gas was experienced just below the 20” shoe after drilling out with SW to perform a LOT. The mud weight was increased to 12.6 ppg, then 12.7 ppg, which was

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used to drill the section to TD. The well was flowing 2-3 bbl/hr on connections, and gas peaks of 43% were recorded. The gas was lagged back to the area below the shoe (±400m). A shallow gas assessment was made after drilling the F-7 well. The conclusion was that well F-9 was to be completed as a shallow gas pressure relief well and put on production prior to drilling out of the 20” casing shoe on F-8. During the completion, F-9 was perforated in 3 intervals just below the 20” shoe (384-390, 440-446 and 485-497m MD RT). The well went on vacuum after being perforated in seawater. Within a few days, gas had swapped around with the seawater, and WHP had increased to 500-600 psi. The well has been flowing gas with minimum draw-down to prevent solids production. The well was shut in when the pressure dropped below water gradient. The estimated pressure gradient at the perforations is +/- 8.5 ppg. The well has been shut in for several months with no increase in Well Head Pressure. 3.3

Gas Cloud The gas cloud as observed in the seismic section (Figure 20) is as a result of upward gas migration over time from the reservoir into upper claystones. The diagram shows how earlier interpretation of seismic data (1992) was difficult due to the high gas content of the claystones, later seismic interpretation (2000) is more accurate. Up to 200m differences can be observed between formation tops between the two interpretations, The “gas cloud” is located in the upper section of the 12 ¼” x 14” hole section at approximately 1550m (+\-50m) TVD it is marked by an increase in background gas values and associated swab and connection gases. The high concentrations of gaseous hydrocarbons can become excessive if rates of penetration are not limited. Higher gas is expected and should not be over reacted to with significant mud weight increases unless well control situations develop.

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Figure 20

Maintain average ROP below 50 m/hr through the gas cloud and if directional control allows, continue with an average ROP of 50 m/hr or less. ROPs in excess of 50 m/hr have previously allowed excessive volumes of cuttings gas into the mud system. (ref. F- 3 A) The following graph illustrates the gas percent recorded on F-3A against ROP while drilling through the “gas cloud”.

ROP versus Gas Comparison F-3 A 120

40 30

80 60

20

40

10

20 0 1600

0 1700

1800 Depth m

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1900

Gas %

ROP m/hr

100

ROP GAS

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The close correlation between high gas values and higher ROP is clear through the gas cloud. Similar gas/ROP correlations are present on other wells. The need to limit ROP through the gas cloud is to prevent the accumulation of “uncomfortable gas levels” in the annulus and prevent the need to stop drilling and circulate through the choke. The gas cloud is approximately 100m TVD thick Gas peaks that were experienced on F3A while drilling the gas cloud, were as high as 20 – 36%. Connection gases were also common over this interval. The gas experienced while drilling the gas cloud is drilled gas. After drilling through the section the gas levels return to normal and the connection gasses disappear. It is essential that there is no over reacting to these higher gas levels. The consequence of increasing mud weight could result in borehole stability problems and the loss of the hole. 4.0

BALLOONING Ballooning is sometimes referred to as breathing – it is the slow loss of mud to the formation while drilling and the return of mud after the pumps are off. Mud losses occur while circulating it is probably due to mud entering fractures with limited porosity as a result of the ECD. Mud gain is due to the loss of ECD when the pumps are off so pressure on the borehole is reduced to hydrostatic pressure. The reduction in pressure results in the fractures closing and the formation ‘exhales’ the ‘lost’ mud. An increase in background gas is often seen as a result Ballooning can occur on Valhall, but it should be avoided if possible. Once ballooning is initiated it is very difficult to recover from it. The constant opening and closing of the fractures will weaken the formation and can result in borehole collapse or the generation of cavings with the possible influx of gas. Mud weight should not be increased, as this will make the situation progressively worse due to a higher ECD. Ballooning can be avoided with careful monitoring of ECD, which should not exceed 15.0 ppg.

5.0

CAVINGS Cavings are often observed from the interval 1500 m to 1800 m TVD/RKB, but these are believed to be more time-dependent and generally should not be a problem. In ERD wells we have had a lot of problems including blocky cavings from the interval 2000 to 2200 m TVD/RKB, but because of the lower sail angle we do not expect this to be a problem in this well. We have seen cavings from the lower part of Eocene and Palaeocene and expect some potential shear cavings from this interval, but these should not cause a problem.

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Cavings have become a decreasing problem in the last four consecutive wells, A-3 D, F-3 A, F-19 and F-15. The generation of cavings was typically related to hole inclination, proximity to faults and hole cleaning issues in the past. The potential problem of excessive cavings and associated well bore instability should not be underestimated. However the trajectory, drilling practices and hole cleaning with the use of a rotary steerable system should eliminate excessive cavings. F-15 encountered significant very large cavings under the 13–3/8” casing shoe follow extended periods of tripping and lack of circulation. This zone will be cased off relatively quickly with the 13-3/8” liner / tie-back. 5.1 Cavings analysis Provides:

A warning signal that the well bore is failing. An indication of which formations are unstable. Evidence of the failure mechanisms. Information for remedial action. Cavings are characteristically 1 – 2cm Smallest: a few mm, so called coffee ground cavings Largest: 10 cm or more, typically blocky or fractured formation Normally transported to the surface by the drilling fluid, but larger samples may be found lodged in parts of BHA or other downhole equipment. Three main types:

Angular: due to breakouts. Tabular: due to natural fractures and/or weak planes. Splintered: due to overpressure.

1) Angular Cavings: due to breakouts •Irregular shape and rough surface texture. •Sheared face is curved. •Surfaces intersect at acute angles Surfaces are natural fracture planes Bedding parallel to surfaces => Failure along bedding planes

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Picture E Picture F Tabular cavings from F13 3847m ( Pic E and Pic F ) showing flat surfaces and bedding planes

Picture G

Picture H

Tabular cavings from F13 T2 2995m (Pic G and Pic H) showing flat surfaces and bedding planes Remdial action for Tabular cavings are: 1) Reduce fluid invasion of natural fractures/Weak planes i.e. decrease fluid loss. 2) Add crack blocking material to the drilling fluid, Calcium Carbonate has been used on previous wells. 3) Employ correct drilling practices to reduce shock to the formation. (See section Drilling Practices). 4) Do not increase mud weight. 5) Optimize hole cleaning with the use of down hole pressure subs measure ECD 3) Splintered: due to overpressure.

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Picture I : Typical splintery pressure caving Two surfaces which are nearly parallel. Elongate splinter-like morphology. Parallel surfaces may exhibit plume structure. Indicates pore pressure exceeds mud weight. Tensile failure occurring parallel to borehole wall. Remedial actions for angular cavings are: 1) If plume structures are evident raise the mud weight. Figure 21:Summary of conditions, which can cause borehole collapse or fracture depending on ECD values and the cavings that the various conditions generate. Note the extreme situations both result in enlarged hole.

Splintered

Angular

Figure 21

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Tabular

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FAULTS Due to the subsidence within the Valhall area, approximately 4m at the seabed and 1m at the reservoir, some faults have become more active. So potentially the risks in drilling these faults has increased. It is also more difficult to predict what problems will be associated with a particular fault as the field is in a dynamic state due to the subsidence. Possible observations drilling into the identified faults are: • Increase in gas • Indication of flow • Lost circulation • Pack-off or sticking tendencies (stuck-pipe) • Sudden change in drilling parameters The following are Valhall fault crossing experiences: • The gas level is reduced by circulating bottoms-up, and making a small increase in mud weight (0.1 ppg at a time.) • The losses stop after a relatively small volume of mud has been lost (10-20 bbl). • Reducing mud weight and the losses are cured - no gas - fault not active. • Reduction in mud weight, but experience pack-offs and sticking tendencies. End up in a vicious circle between losses and pack-offs. • Soak the wellbore with LCM cocktail to stop losses. • Cement the fault zone and hope to drill through a cemented fault-zone when the cement cures. • Cement the fault-zone and use a contingency sidetrack trajectory. • Complete lost circulation, run casing / liner higher than planned.

6.1

Guideline For Problematic Faults

The effects on wellbore stability of the faults will not be known until drilling into the faults but an awareness of their potential will be maintained by the DOEs. If no wellbore instability is apparent, no reason for reducing ROP is necessary.

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If high gas is the problem: 1. Stop drilling and circulate bottoms up to see if gas comes down with current mud weight (high pressure could be low permeability and small volume). 2. Check predicted fault versus current location. 3. Increase the mud weight in 0.1 ppg steps to control gas levels, if needed. 4. Do not overreact to the gas or increase the mud weight too much as this may result in losses and evolve into a loss/collapse circle with “hole ballooning”. If losses are the problem, consult the lost-circulation decision-tree in the Mud Management sections for each relevant hole section. In case of losses or deteriorating well conditions: 1.

Circulate down a LCM cocktail to plug fractures.

2.

Check type and volumes of cuttings and cavings.

3. If the hole situation does not improve, increase the mud weight slowly after the well has stabilised (LCM has cured losses). 4. If unable to drill ahead, discuss options with town. If experiences indicate that this fault crossing point is non-optimal, we will go back to the shoe and drill the contingency trajectory if we have one. For this well there is not identified a optional trajectory because of the target restrictions. Main notes: • Control ROP when experiencing high gas readings. • Only weigh up in 0.1 ppg steps to avoid unnecessary problems. • Avoid extensive circulation, rotation, directional work, surge and swab across faults. • Analyze what is happening downhole • Have a clear and well-understood plan in place. 7.0

WASTE DOMAINS Based on historical information, waste domains should not present an interference problem N.B. Communication between the F- 3 A well and the currently active injector well A20D was considered to have occurred.

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Waste Injection wells on Valhall

The planned well trajectories are around the disposal domains, including a safety factor. Careful observation should be made when approaching these domains, as there is the potential for seawater contamination of the drilling mud. Mud chemicals should be available for any possible mud treatment required due to the saltwater contamination. Smaller waste disposal domains have been penetrated without significant problem in other fields, but domains of the size of these have not been penetrated. In A-16D 97,625 bbls waste-water was injected at 1484 m MD, 1362 m TVD. Estimated radius is 70 meter (suggested safety factor is 2). In A-3B 574,000 bbls was injected at 1310-1320 m MD, 1240-1250 m TVD, estimated radius is 70-100 m (suggested safety factor is 2). All these depths are in M RKB. Below is a montage of the A-16E trajectory and how it has been planned to avoid the waste domains in A-16D and A-3B. The predicted domain extensions are in red and the safety factor is shown in blue.

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A-16E v1.4 A-16D

A-3D

A-3B WASTE ZONE A-16D WASTE ZONE

Fig 24: An OpenVision 3-D Display of the A-16E well trajectory and the waste domains in A-3B and A-16D.

The domains have high pressures even after several years (the wellhead pressure during a one year injection break in A-20D only dropped 200 psi, with the injection point being at around 2000 m TVD). The big question is how much “free” water is present in this pressurized clay and will it flow? We do not really know. The material itself should be very similar to “quick-clay” because of the high internal pressure and the low cohesion of this material. If we penetrate the waste domain and experience backflow of seawater and waste, we should treat this as a kick (well control incident). Based on the maximum pressures observed between the injection cycles, the pressure at the perforations in the injection wells at the end have been estimated to 20.1 ppg and 21.2 ppg for A-3B and A-16D respectively. The pressure declines with time. Please note: • Potential for saltwater contamination of drilling fluid • Potential for saltwater/waste kick. • Need to be ready to inject returned waste volumes into the available waste injector

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DRILLING PRACTICES

8.0

8.1

Drilling Practices and Optimisation

Drilling practices on Valhall are intended to limit the pressure exerted on the wellbore to a maximum ECD of 15 ppg in the 14” hole and 15.3 ppg in the 12 ¼” hole. Hydraulics and hole cleaning concerns have been designed around this plan and to prevent excessive gas in the mud system. Offset data has shown that with annular pressures greater than 15 ppg, losses and consequential wellbore instability can occur. Wellbore instability makes ECD and hole cleaning extremely difficult to control on Valhall wells. It is essential that drilling practices are followed any minor deviation from the practices could result in the loss of the well. 8.1 • • • • • • • • • •

Good Drilling Practices

Always maximize pipe motion in open hole Maintain circulation on connections for as log as possible Always break circulation on the up stroke Monitor and record depths of higher torque and/or stick slip Always monitor the shakers to ensure adequate cuttings return and check for the presence of or increase in the volume of cavings. If pump repairs are necessary, stop drilling if adequate hole cleaning cannot be guaranteed with one pump Be prepared to limit ROP if hole cleaning is poor Follow connection procedure for bringing the pumps slowly to avoid shocking the formation. If hole conditions dictate perform a wiper trip Maintain correct mud specifications

8.2

Flow Rates Ensure flow rates are adequate to clean the hole with worst-case scenarios in mind including mud properties and no rotation. Flow rates required to clean the hole are specified at the start of each hole section.

8.3

Connection Procedure

The connection procedure below is a guideline to what practice is required to minimise ECD surges during operations. The procedures can be varied according to operational requirements, and field experience. The main priority for ECD management remains slow initiation of circulation. Key issues

• •

ECD peak when resuming circulation Swab / surge risk

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The following connection procedure has proven successful in preventing pressure spikes following connections. 1. 2. 3. 4. 5. 6. 7. 8.

9. 10. 11. 12. 13. 14. 15. 16. 17. 18.

Drill down stand. Pull ± 2m off bottom Take torque and drag readings Stop rotation Work torque out of string if necessary Activate the brake (keep string still) Decrease flow below lower tool operational limit (approx 500 gpm) Increase flow to above lower operational limit (approx 600 gpm) Continue pumping until survey is registered at surface reduce pump rate to below the activating flow for the under-reamer, pull up a maximum of 2.5 joints, turn off the pumps, run down and make connection (this exercise can help to level out cutting beds and help to give a better picture of the hole condition). In the 14” hole, do not pull the entire stand up to avoid pulling the Autotrak ribs into the 14” hole. Set string in slips (Do not make connection if gas levels increasing significantly) Make connection Fill pipe until pressure shows string is full then reduce to 10 spm Pick pipe out of slips Start rotating the drillstring (30 - 50 rpm) (if in rotary mode with motor in the 12 ¼” hole) Observe return flow Increase to 35 spm while observing increase in return flow. Do this slowly over the course of 30 seconds. Increase flow rate to drilling rate over a further 30 seconds while observing increased return flow. Wait another 15 seconds before moving string to bottom. Bring up to full rotation while bedding in bit. Resume drilling.

The drilling personnel became familiar with connection procedures quickly, but required continued DOE monitoring to ensure connections were made without error. Anadrill MWD service requires a different connection procedure to minimize pressure surges was as outlined below: 1. 2. 3. 4. 5.

Drill down stand. Pull +/- 2 m off bottom Wipe stand with full drilling circulation rate Run the string back to +/- 2 m off bottom, take off bottom torque and drag measurements Work torque out of string if necessary Set string in slip

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6. Turn off pumps 7. Make connection 8. Pick pipe out of slips 9. Start filling pipe 10spm 10. Start rotating the drillstring at 60 rpm. If orientation is required after connection and the initial pressure required to break the gels is over 150 psi above SCR at 10spm then rotation should be employed to assist in breaking gels. If breaking pressure is less than 150 psi above SCR then no rotation is necessary. 11. Reduce rpm to 0 before returns are gained. 12. Stage up pumps to 50 spm, at a rate that well conditions allow. Extra time may be used here if well conditions dictate 13. From 50 spm to 90 spm increase pumps as quickly as conditions allow. As fast as reasonably practical to allow survey to be taken. 14. MWD will call when data is being transmitted. 15. Continue staging up pumps to full rate. 16. Bring up to full rotation while bedding in bit. Resume drilling.

Plot 5: Increasing pump rate too quickly resulted in a pressure spike of 0.4 ppg, this could be enough to cause severe wellbore stability problems and possible loss of the section.

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Plot 6 Connection procedure good, with a very small pressure increases, initial flow is 55 – 60 gpm for 1 minute. Followed by a slow increase to full flow rate over 3 minutes

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Plot 7 Connection procedure initially good, initial flow is 55 – 60gpm for 1 minute. Followed by an increase to full flow rate over 2 minutes. This small difference of 1 minute in the build up to full flow was enough to cause a significant pressure spike

8.4 8.4.1

8.4.2

Tripping

Circulating Prior to Tripping Out Of Hole •

Circulate at least 2 ½ times bottoms up at the minimum rate required to clean the hole

•

Use an RPM of 130 – 140 to optimise hole cleaning

•

Reciprocate string slowly while circulating and rotating to avoid cutting drillstring across stringers

•

Be aware that under-reamer is likely to continue to generate cuttings

Tripping Speed On reviewing the post well data from the memory of pressure subs, the effect of tripping speed on swab and surge has been concluded as follows: •

Tripping speeds of 2 mins per stand should be adhered to across the majority of the hole section

•

Tripping speeds of 3 mins per stand should be applied in the following circumstances: When running the BHA through the casing shoes. When running the last 5 stands to TD Particular attention should be given to “tight” zones or stringers while tripping to limit mechanical damage 8.4.3

Tripping In Hole Shear the mud in the active pit and aim to keep mud temperature above 120 deg F. When running in hole, break circulation at least once prior to entering open hole and at least every 500 m in open hole. It is recommended to break circulation in 250 m intervals in the open hole and then adjust up to a maximum of 500 m depending on ECD values seen while circulating. Break circulation as follows: 1. Fill pipe until pressure shows string is full then reduce to 10 spm. 2. Break circulation on the upstroke 3. Start rotating the drillstring (30 - 50 rpm) 4. Observe return flow

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5. Increase to 35 spm while observing increase in return flow. Do this slowly over the course of 30 seconds. 6. Increase flow rate to drilling rate over a further 30 seconds while observing increased return flow 7. Gradually increase rotation to 100 rpm while carefully monitoring pressures from ECD sub to help break gels.

Plot 8 A high surge pressure resulted from running the BHA through the 13 3/8” casing shoe on A3D too quickly. A running speed of 3 min per stand should be used entering the casing shoe and rat-hole.

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Plot 9: A increasing surge pressure is observed on A3d running the last 5 stands to bottom. A running speed of 3 min per stand should be used for the last five stands above bottom. 8.4.4

Tripping Out of Hole 1. If hole conditions are good and swabbing is not expected (particularly above 1500 m TVD), attempt to trip out conventionally. Trip first 5 stands wet, slug pipe and continue to POOH at 2 mins/stand. If swabbing is recorded, pump out of hole as per procedures in step 2 below. If tight spots are seen, work string down and work over tight zone. Never pull more than 30 klbs overpull. If there are stringers in the BHA area, attempt to ream through with slow pipe rotation (30-50 rpm) with no circulation. Run back down and attempt to pull through obstruction again. Do not rotate in the same place for more than 5 - 10 mins. If the hole is still tight, RIH a minimum of 1 stand, start rotating at 30 - 50 rpm and break circulation as per tripping in procedure. Circulate hole clean prior to continuing trip out of hole. 2. If unable to pull out of the hole without swabbing, pump out of hole with a flow rate of 150 gpm and a typical tripping speed of 2 mins/stand. When inside casing, attempt to trip out conventionally. If tight spots or pack offs are recorded, shut pumps off and work string down into a free area. Start rotation at 30 - 50 rpm without circulation and attempt to ream through obstruction. When through the obstruction, wipe the area once. Stage-up pumps and wipe the area once more while closely watching drillpipe pressure.

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3. If steps 1 & 2 are unsuccessful, back ream out of hole. If backreaming out of the hole, the objective is to both work through the obstruction and move cuttings beds up the hole. Steps 1 & 2 are designed to trip through cuttings beds. Back ream out at full circulating rate used for drilling and 130 - 140 rpm. Stage up pumps and RPM as per normal procedures for each stand. Backream out till stand is ± 3m above rotary table, circulate for ± 5 mins, reduce rotary and turn off pumps. Break connection. Back ream out at 3 - 4 mins per stand. Carefully monitor ECD while backreaming to avoid overloading the annulus. If ECD is approaching limit, reduce RPM while maintaining circulation rate. Monitor returns over shakers and if cuttings volume increasing, circulate bottoms up every 5 stands. Consider going back to step 2 if hole conditions improve.

Plot 10

8.4.5

Running pipe in too fast causing pressure surges

Backreaming

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Back reaming is not anticipated. Backreaming should not be necessary with the use of a rotary steerable system (RSS) as the continual rotation does not produce the “ledges” created by conventional motors. Backreaming will be at the discretion of the directional drillers, depending on hole conditions, angle, and available surface RPMs of the motor.

8.4.6

Wiper Trip Guideline No wiper trip is planned for at TD of the hole sections or over intermediate depths. However, wiper trips may be performed if hole conditions dictate. The following are intended as a guideline if wiper trips should be considered: a) Does the theoretical vs. actual cuttings-removal / mud-loss plots, provided by mudloggers, suggest the hole has been cleaned? b) Is there persistent drag, over and above, the normal trend during connections and backreaming? c) Has “spotty” torque been recorded over the lower hole section suggesting cavings in the annulus? d) Does the ECD sub confirm the hole is clean?

8.5 Running Liners - WIP 9-5/8” Liner Running and Cementing Operations 11 ¾” liners have been run on Valhall as a contingency in the event of unforeseen hole problems. Due to the weak formation surge pressures must be kept as low as possible to avoid major losses/ borehole collapse while running in. Due to the small clearance when running in the 11 ¾” liner, flow diverter tools have been run which reduce surge pressures considerably. The following objectives are required on WIP which will run a 9-5/8” liner. Objectives • Run 9-5/8” liner to 50 m TVD above the Intra Late Eocene with minimum surge damage to formation. • Provide a seal with cement at the shoe that is sufficient to drill the next section without creating any formation stability problems below the shoe. After cementing allow the mud weight to be increased from 14.6 ppg to 15.0 ppg without any losses. • Set an integral liner hanger packer inside the 13-3/8” casing to provide a seal against any potential flow of formation fluids - no cement in liner lap. General The 9-5/8” liner is set just above the Intra Late Eocene to cover the weak zone below the 13 3/8” shoe, the gas cloud and potential troublesome faults. 1.

It is of utmost importance that the hole is 100 % clean prior to run casing.

2.

Liner overlap is planned to be ±50 m into the 13–3/8” casing.

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3. 4.

Liner is usually run slick. In order to minimise surge pressures while running and avoid taking returns up the drill string, the liner can be run with a flow diverter tool (Baker Oil Tools Hyflo valve or with a 4” bore running tool Type: BIG BORE and a flow diverter tool (Weatherford/Allomon)) installed 1 stand above the liner running tool. This tool when open diverts the flow coming up the liner through ports to the 5 ½” DP x 13 3/8” casing annulus. The tool is closed by a 2 ¼” brass ball that is allowed to free-fall to the tool (same ball that is used for activating the setting of the hanger).

The following actions can be applied to reduce surging of the formation while running the liner. 1. A float less liner with surge reducing diverter will be run 2. Running speeds will be optimised based on returns observed 3. Pick-up and set-down in the slips will be consistent and slow 4. Actual hookload will be plotted vs. theoretical to determine cuttings build up/hole condition. (See example plot 11) 5. No attempts will be made to circulate in order to break circulation, stage in or to warm up mud, this is to prevent formation damage and losses. (Ref F3A). Plot 11: pick and slack off weights running 11 ¾” liner contingency F19

2/8-F-19, M. Guardian Running in with 11 3/4" 65.0ppf Liner w/250m 5 1/2" HWDP & 5 1/2" DP to Surface (78000 lbs Block weight included.) 350000

20000

340000

Theor. S/O Hookload

330000

Theor. Torque

Theor. P/U Hookload

18000

Start to pull the string a few metres.

Actual P/U Hookload

320000

13 3/8" Csg at 1585mMD

Actual S/O Hookload

310000

16000

Actual Torque

300000 290000

14000 Torque [ft-lbs]

Hookload [lbs]

280000 Hookloads taken from mudloggers charts full hookload not neccesarily required to pick string up from slips

270000 260000

12000

250000

10000

240000 230000

8000

220000 210000

6000

200000

Friction Factor; Ff_csg. : 0,12 Ff_csg vs liner= 0.17 Ff_ open Hole= 0.39

190000 180000

4000

170000

2000

160000

Measured Depth [m]

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2200

2100

2000

1900

1800

1700

1600

1500

1400

1300

1200

1100

1000

900

800

700

0 600

150000

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Limestone Stringers

Limestone stringers increase in frequency towards the end of the overburden section. A record of all limestone stringers is kept on the drill floor to assist the driller during trips. Limestone stringers, when pulling out of hole, have frequently given mechanical overpull and packoff problems on Valhall wells. On F-19 the only problems when pumping out of the 12 ¼” hole were associated with limestone stringers. Fortunately, the frequency and thickness of the limestone stringer intervals on F-19 were much less than on F-3A, and they did not prove a serious problem. What was noted on F-19 was that after pumping slowly though troublesome stringers (with overpull and pack-off tendency), the zone was then wiped and the problem fully alleviated. For future wells, with a greater frequency of stringers, the wiping of such zones prior to drilling to TD should be considered seriously, with the implementation of wiper trips should it be necessary. Packing off has occurred across the limestone stringers where cuttings beds may build up, this is more commonly seen when an under reamer is in the string.

Hard limestone stringers in relation to sliding directional activities

From the outset it was planned to rotate through limestone stringers. From a practical viewpoint, if sporadic thin stringers of indeterminate zonal thickness are encountered during a steering interval, the tendency of the directional driller is, if the toolface remains true and ROP tolerable, to proceed steering. On one occasion during the 12¼” section of F19, when dropping through a thin stringer in steering mode the motor immediately stalled giving a pressure increase of 500 psi above normal drilling pressure. This pressure was only held momentarily before the motor became free. The release of the drillpipe pressure gave a pressure surge in the annulus, measured at 15.15 ppge EMW (MW 14.6 ppg, drilling EMW 14.85 ppge). In this case, the pressure surge was held by the formation without consequences, however in weaker formations these short-lived pressure pulses may be sufficient for fracture generation and subsequent borehole stability problems. An increase in drag is often associated with these limestone stringers and often an increase in torque.

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Torque and Drag

The torque & drag plots are an essential tool for monitoring both hole cleaning and borehole stability. It is essential that pick up and slack weights are recorded on each connection along with torque.

The theoretical torque & drag data, calculated with Baker Hughes Deapteq software using friction factors refined over several wells to accurately represent Valhall formations, are plotted prior to drilling and running casing. The data can then be used as a guideline, against which the actual values are plotted. A plot is kept on the drillfloor, and regularly updated by hand after each connection, as well as on the DOE computer. Close monitoring of these plots during F-15 and previous wells allowed the DOEs to accurately determine hole condition, with regards to cleaning and stability. It was seen on F-15 and previous wells, that two phenomena give characteristic increases in hole drag; 1. Limestone stringers, which by their nature give increased mechanical drag. Experience has shown that this drag increase is little to do with borehole stability, but does have consequences when pulling out through the stringers. 2. The Balder Formation, which is typified by borehole instability. The current learning is that any increase in hole drag on Valhall wells which is not related to the two examples above is almost certainly due to inadequate hole cleaning. In such cases it has been seen that circulation with rotation will clean the hole and reduce the drag. .

Plot 12: torque and drag plot

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frequent limestone stringers

320000 Calc. Slackoff Hookload

310000

Calc. Pickup Hookload

300000

Actual Pickup Hookload

290000

Calc. off bottom torque

Actual Slackoff Hookload

occasional limestone stringers

up to 20% cavings (related to top Balder)

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2/8-F-19, M. Guardian Drilling with 12 1/4" Speedreamer and 8" M1XL to TD at 3367m 11 3/4" Liner shoe at 2164mMD (78000 lbs Block weight included.)

21000

19000

220000 210000 200000

TD at 3367m. Circ clean, increase MW to 14.7 ppg

circ BU at 3333m

circ BU at 3251m & 3260m

17000

15000

13000

Torque [ft-lbs]

230000

circ BU at 3191m

240000

circ BU at 3077m & weigh up to 14.6 ppg

250000

circ BU at 3020m

260000

drill with 14.5 ppg mud

11 3/4" Liner at 2164mMD

270000

circ BU at 2907m

Actual off bottom torque

280000

Hookload [lbs]

Rev:

11000

190000

9000

180000 170000

7000

Friction Factor; Ff_csg. : 0,12 Ff_ open Hole= 0.13

160000

3500

3400

3300

3200

3100

3000

2900

2800

2700

2600

2500

2400

2300

2200

2100

5000 2000

150000

Measured Depth [m]

8.8

Cycling Pumps If problems occur with MWD/ Autotrack / Powerdrive tools it is bad practice to cycle the pumps. Bringing the pumps up too quickly will cause pressure spikes. The procedures for pumping as mentioned in the connection procedure should be followed at all times. Plot 13 On A3D the pumps were cycled which resulted in a pressure spike up to 15.18 ppg.

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LOST CIRCULATION

Lost circulation has been common problem on Valhall. Losses can occur to faults, natural fracture or mechanically induced fractures, Solution to Lost Circulation Problems • Recognition of the loss • Identification of the cause of the loss • Location of the “thief” zone • Proper remedial treatment to combat the loss Recognition of Borehole Problems May be made by: • Pit volume totalizer (PVT) • Flow return sensor • Pump pressure reduction • Drilling break - often first indication Mechanically induced fractures One of the main causes of lost circulation on Valhall is mechanically induced fractures Causes 1. Running in too fast after trip producing high surge pressures. Also when running casing. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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2. Excessive pump pressure to break circulation after trip. 3. Cuttings or sloughing shale close off annulus --pressure build up in system. 4. High gel strengths & viscosity -- requiring higher pump pressure to break circulation 5. Unbalanced mud column -- raising mud weight too rapidly. 6. Opening pumps too rapidly. 7. Pipe whipping. 8. Pressure developed while killing a well. 8. Effective circulating density greater than fracture gradient. Preventative measure to avoid inducing fractures 1. Rotate drill pipe before starting pump -- a lower pressure will be required to break circulation 2. Break circulation slowly 3. When running in hole, do not run in too fast and break circulation at intervals 4. Avoid thick wall cake which reduces hole diameter and can thus increase surge pressures 5. Maintain the minimum mud weight necessary to control the formation pressure of the borehole 6. Avoid excessive annular velocities which result in high annular pressure losses, and thus high circulating pressures 7. Maintain the minimum mud viscosity, gel strength and yield point to prevent settling of the weight material

On Valhall, the commonly used type of LCM is the Norwegian blend Pre treatment of the mud with LCM is not recommended because: 1. 2. 3. 4. 5. 6.

Expensive Some materials lose their strength, especially fibrous materials L.C.M. removed by shaker; bypassing shaker retains material. Material - increasing weight of column and possibly aggravating the problem Higher circulation pressure required with L.C.M. in mud, due to increased viscocity Possibility of Plugging

9.1 LCM Decision Tree for Valhall If any losses are experienced, consult the decision tree below. The following loss circulation decision tree formulations have been developed after consultation with BHI Fluids. Pill concentrations can be modified dependent on operational circumstances using the same ratio of LCM materials. At higher concentrations, the pill formulations can exceed the specified operational LCM concentrations for the downhole tools. This will be an accepted risk.

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Figure 25 Lost Circulation Decision Tree Overburden oil based Losses Decision Tree Prior to Fault or Expected Loss Circulation Severe loss > 20 bbl/hr OBM Consider to adjust PILL. 100 bbls or Greater : Directly to Gunk or

Partial loss >10 - < 20 bbl/hr OBM Consider to adjust PILL

Seepage loss 10 bbl/hr or less OBM

Alternative pill \ cement

Down Hole

Initially Mix 5 ppb of LCM OM Seal and Nutplug F. Then continue to mix 3 sx Nut Plug F and 2 sx OM Seal per hour as required for maintenance. This may be added as back ground or used as a Sweep. Repeat if positive results. Yes Success ?

Spot 100 bbl pill 30 lbs/bbl Mica Fine 30 lbs/bbl Nut Fine 10 lbs/bbl OM Seal or Checkloss 15 lbs/bbl Ultraseal Plus or Venfyber 10 lbs/bbl CaCO3 (M), 5 ppb LC Lube Pull up and wait one hour while circulating. When LCM pill enters BHA reduce flowrate To minimise plugging the tools ( 200 – 250 L\min)

Spot 100 bbl pill 30 lbs/bbl Mica Fine, 5 lbs/bbl Mica Med 30 lbs/bbl Nut Fine, 5 lbs/bbl Checkloss 15 lbs/bbl OM Seal, 5 ppb LC Lube 20 lbs/bbl Ultraseal Plus 10 lbs/bbl CaCO3 M \ 10 ppb CaCO3 F. Reduce flowrate to avoid plugging tools. (200 – 250 L\min) Pull up and wait one hour while circulating Yes Continue to Drill

Success No

No Sweep 50 bbl pill with 10 lbs/bbl Mica F 10 lbs/bbl Nut F 10 lbs/bbl OM Seal 10 lbs/bbl Ultraseal Plus 10 lbs/bbl CaCO3 M

Pump 15 -20 bbls viscosified spacer followed by 40 - 45 bbls gunk squeeze from the batch mixer followed by 15 - 20 bbls viscosified spacer and spot , pull above and wait 30 minutes while circulating.

Success

Yes

No

Yes

No Success

No Success

Increase Density 0,1 - 0,15 ppg

Pump 15 -20 bbls viscosified spacer Followed by 40 - 45 bbls gunk squeeze from the batch mixer followed by 15 - 20 bbls viscosified spacer and spot , pull above and wait 30 minutes while circulating. Yes

Yes

Success

Drill Ahead Alternative materials for use Superseal, LC Lube, Checkloss M, Ultra Plug. It must be noted that with the higher ppb Pills tools may plug or malfunction.

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Pump the gunk pill down the drill pipe at a rate of 2 bbls/minute. At the same time when spacer and pill are at the bit pump down the annulus at 0,5 bbl/minute.

No

POOH to Cement or Run Casing

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LCM Particle Size Distribution

Material

D 10 (microns)

D 50 (microns)

D 90 (microns)

Calcium Carbonate

1.2

10.0

40.0

3.6

35.9

140.0

50.0

336.0

545.0

9.0

46.0

92.0

120.0

270.0

150.0

600.0

880.0

1000.0

1500.0

1800.0

Mica Fine

150.0

300.0

700.0

Mica Medium

200.0

800.0

1000.0

Venfyber 201

16.0

43.0

219.0

LC LUBE

160.0

250.0

800.0

OM Seal

150.0

1000.0

2000.0

Fine Calcium Carbonate Medium Calcium Carbonate Coarse Ultraseal XP

Checkloss

Nutplug Fine Nutplug Medium

10.0

STUCK PIPE

Stuck pipe is not inevitable if you: 1. Communicate effectively. Keep your team members regularly informed of what the hole is saying. What may seem trivial to you may be vital to someone else. Ensure hole condition is recorded and handed over at shift change. Most stuck pipe occurs around shift change. 2. Plan ahead. Always know what formations/potential problems are coming up. Have contingency plans ready in case trouble strikes. (Response to overpull, mud changes etc…) 3. Listen to the hole constantly. Torque, drag, cuttings, pump pressure are all indicators of hole condition. Record all information; this will help identify important trends. Changes in trends may indicate hole problems. 4. Maintain good mud. Keep all mud properties within specification, especially density, rheology, low gravity solids and fluid loss. Analyze reason for change in any mud properties. 5. Keep pipe moving, whenever possible when in open hole. (Reciprocation preferable to rotation) 6. Clean the hole as fast as you drilled it. Remember that overgauge and directional holes require faster circulation to clean them effectively. Always circulate before tripping. 7. Take action early to fix sticking pipe problems, don’t let them get bigger. Stuck pipe and hole cleaning problems will hardly ever cure themselves. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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Mechanical Freeing of Stuck Pipe, General: See also BP Stuck Pipe Handbook section 7.6 - 7.8. Assume mechanically stuck and begin remedial action immediately. • Always pull the string immediately to maximum in the opposite direction running since this was the direction it got stuck. • Establish circulation if possible. Be clear of the effect |of establishing circulation has upon the jar. • Work the String Downwards: Work torque in the string down to stuck point. Normally 0.75 turn / 300m. Be clear of the effect on jar. Slack-off downward and let the jar fire. • Work the String Upwards: Control the increase in strain gradually until using max load permitted one time. • Either Direction: Start to work the string. Start with jarring with 40-50.000 lbs over the limits set for activating the jar. Increase the weight applied to the jar gradually over time. Do not exceed the maximum pull limits set for the string. • Opposite Direction: Start to work the string to maximum load strain limits. Remember: Work the string, allow the jars to fire, so that working the string to maximum limits is done with the jar uncocked. 11.0

CEMENT BLOCKS

11.1

Cement-blocks falling on top of BHA /stabilizers. • • • •

Keep milling/ OBM fluid in spec. Have Jars in BHA Avoid backreaming. Avoid unnecessary rotating and circulation to avoid washouts and breaking off cmt blocks. • If tight, work string down to free. Use jars upwards to crush cement-blocks. /var/www/apps/conversion/tmp/scratch_1/144303219.doc

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Do not exceed flow rate necessary to clean the hole. Avoid unnecessary circulation and rotation in open hole. Trip carefully past the loose formation. If tight hole, trip down to clean hole below weak zone.

Cement Blocks in the rathole • • • •

Drill carefully, check free upwards frequently. Ream rathole and shoe several times. Avoid unnecessary circulation in open hole. If cement blocks, jar to crush them. Avoid hard pumping, creating cave and more loose blocks. • Have RSS outside shoe before kickoff.

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