02 Downhole

February 9, 2000 Halliburton Company (Dallas, Texas) 2-1

2Section

Downhole Service Operations SL 2.1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Depth Measurement ConsiderationsSL 2.2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Gauging OperationsSL 2.3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Perforator Dummy UseSL 2.4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Swaging OperationsSL 2.5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Broaching OperationsSL 2.6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Use of Impression BlocksSL 2.7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paraffin Cutting and Scale RemovalSL 2.8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selection and Use of Flow ControlsSL 2.9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . W Slip Lock SystemSL 2.10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .D Collar Lock SystemSL 2.11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .S, N & T, Q EquipmentSL 2.12 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . X - XN & R - RN EquipmentSL 2.13 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RPT Lock SystemSL 2.14 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RPV Lock MandrelSL 2.15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SAFETYSET® Lock SystemSL 2.16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FBN Lock SystemSL 2.17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Monolock® SystemSL 2.18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subsurface Safety Valve ConsiderationsSL 2.19 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Running and Pulling Gas Lift ValvesSL 2.20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Running and Pulling PackoffsSL 2.21 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Opening and Closing Sliding SleevesSL 2.22 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Use of Test ToolsSL 2.23 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bailing OperationsSL 2.24 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General BHT/BHP SurveysSL 2.25 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Caliper SurveysSL 2.26 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Perforating (Otis Type ‘A’) MechanicalSL 2.27 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Swabbing OperationsSL 2.28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Using Kinley Power JarsSL 2.29 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General Wireline Fishing OperationsSL 2.30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General ETD OperationsSL 2.31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Running Long Assemblies with PressureSL 2.32 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shifting (Knocking) Off TCP GunsSL 2.33 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Use of Downhole Purge/Surge ValvesSL 2.34 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deviated Well OperationsSL 2.35 . . . . . . . . . . . . . . . . . . . . . . . . . . . . High Pressure/Temperature OperationsSL 2.36 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Downhole Power Unit OperationsSL 2.37 . . . . . . . . . . . . . . . . . . . . . Memory Production Logging (MPL) Operations

Slickline Operations Manual SL 2.1: Depth Measurement Considerations

SL 2.1: Depth Measurement Considerations

1.0 ScopeWireline depth measurement is a means to determine the location of various com-ponents in the wellbore from the surface or a known reference point. In addition, it can be used to locate fluid levels and other points of concern in the wellbore. Repeatable and accurate depth measurement is extremely important when ana-lyzing wellbore problems and during wireline fishing operations.

2.0 General InformationSeveral factors that effect slickline depth measurement include:

• Line stretch

• Line slippage through the counter wheel(s)• Counter wheel selection

• Expansion and contraction of the counter wheel due to temperature• Line expansion and contraction due to wellbore temperature

• Counter wheel wear• Tubing Measured Depth Inaccuracies

• Buoyancy of the line in fluid• Wellbore friction on the line

Typically slickline depth measurements seldom match up with the Measured Depth of the tubing in a well. This is primarily due to the environmental stress factors which affect the true depth measurements made for tubing and slickline.

Tubing MeasurementBefore we can discuss slickline depth measurement we must first discuss the way tubing is measured. Tubing is typically measured on the pipe rack a row at a time.

Zero Reference PointSlickline depth measurements should always begin from a zero reference point at the surface. This is typically the Tubing Hanger Flange (THF) on the producing wells and the Rotary Kelly Bushing (RKB) if a drilling rig is on the hole. In the absence of a tubing hanger flange or head, use the lowest master valve as a point of reference and note it in the job log. The bottom of the tool being run in typically zeroed.

Depth measurement can be recorded as Slickline Measurement (SLM) or Wireline Measurement (WLM) and should be noted as such in the job log to distinguish it from the Measured Depth (MD) of the production tubing.

All tubing measurement is from the rotary kelly bushing (RKB). The difference is height between the RKB and the tuging hanger flange (THF) is called the eleva-tion. The accuracy of slickline depth measurement is critical when performing such operations as pinpointing holes in the tubing, running packoffs to isolate holes in tubing, perforating, setting bridge plugs, setting flow controls that are rel-

Slickline Operations Manual SL 2.1: Depth Measurement Considerations

atively close together at depth, determining fill from the end of tubing, etc. At other times the slickline depth measurement is not as critical, for operations such as cutting paraffin, scale removal, etc.

3.0 Procedure1. Inspect equipment (For Mechanical Counter)

a. Confirm that the counter wheel is the correct wheel for the size of wire being used.

b. Check for worn counter wheels and pressure wheels.

c. Check the counter cable for kinks or pinched spots.

d. Confirm that the counter will zero properly.

2. All equipment (lubricator, pulleys, tree connection, etc.) should be in place over the wellbore and hung at the proper height prior to zero.a. Zero at the RKB (Rotor Kelly Bushing) when working with a rig on the well.

- Zero at the THF (Tubing Hanger Flange) when working with a tree installed on the well.

b. Add elevation to the SLM when zero at the THF for RKB measurements.

-Subtract elevation from the SLM when zero at the RKB for THF measure-ments.

c. Zero counter when the bottom of the tool string is at the RKB or THF.

d. Zero counter with running and pulling tools prior to assembly of devices to be installed or removed.

3. Re-zero counter prior to each run. The counter may not return to zero when we pull the wire out of the hole, due to weight difference going in the hole compared to pulling out of the hole.

a. Slippage in the counter head may occur due to worn wheels and pressure wheels not being tightened properly.

4.0 AppendixSee wire chartsAngle correction chart (Martin Decker)

Slickline Operations Manual SL 2.2 Gauging Operations

SL 2.2 Gauging Operations

1.0 ScopeSlickline gauging operations are used primarily to locate reductions in tubing ID and determine the maximum diameter of tools that will pass through the well-bore. Gauging operations are performed prior to running or pulling any wireline- retrievable flow control device (locks, plugs, safety, valves, etc.) from a well.

Gauging operations may also be used to clean up minor scale or paraffin deposits and to locate the depth of various components and fluid levels in the wellbore.

2.0 General InformationSeveral different tools may be used to gauge a well, but the primary toll used in slickline gauging operations is the gauge cutter. It may also be referred to as a gauge or gauge ring.

The gauge cutter (Figure 1) is a short hollowed cylindrical-shaped tool approxi-mately 9 to 12 in. in length with the sides machined out to allow for fluid by-pass. The gauge area of the gauge cutter is usually 1.5 to 2 in. in length. It is used to gauge the ID of the wellbore to determine if there are any restrictions that would prevent other tools from passing through. The gauge cutter may also be used to determine the depth of various components in the wellbore and can also be used to remove minor deposits of paraffin or scale from the tubing walls. A gauge cut-ter should always be run in the well prior to running or pulling any wireline set or retrievable flow control device from the well bore.

Gauge Cutter HistoryHistorically, gauge cutter OD’s have come in 1/32 in. (.031 in. increments) and are still used this way in some locations, which may or may not suite the application. A full gauge, as it is called, is approximately 1/32 in. under the drift ID of the tub-ing that it is to be run in. A full gauge will sit down on the first nipple it encoun-ters in a wellbore and is used primarily to gauge the ID of the tubing where nipples or other restrictions in the ID are not present. A turned down gauge is basically a gauge that has an ID that will drift a nipple or other restriction in the tubing. Typically these are built with an OD 1/32 of an inch under the ID of the nipple it may encounter. (See table 1 for a list of current Halliburton part num-bered gauge cutters.)

Gauge Cutter OD SelectionAs a general rule, to prevent a lock or tool string from hanging up or getting stuck in the wellbore, a gauge cutter of equal OD to the largest size tool that will be run in the well should be run first. For tubing, a gauge cutter with an OD 1/32 in. less then the drift ID of the tubing (full gauge) should be run. For wells that will require the setting or removal of a flow control from a nipple, a gauge OD that is .010 in. under the ID of the nipple and between 1.5 and 2 in. in length at its largest OD should be run first. This matches the largest OD of most known no-go type lock systems. If the flow control incorporates a no-go sub (N type) or no-go type equalizing valve housing (XO or RO type) then a gauge that is .005 in. under the nipple ID and between 1 in. and 1.5 in.in length should be run prior to running or

pulling the device. The no-go subs and rings on the equalizing valve housings are the largest OD’s that will be encountered in this case. If the proper size gauge cut-ter as outlined above is not available, then use the largest OD tool that is closest to the guidelines above.

3.0 Procedure1. Gauging the well:

a. Select the proper size gauge cutter for the relevant tubing size and nipple sizes. If the gauge cutter is to be run in a flowing well, ensure that enough stem weight is added to overcome well pressure and friction acting on the wire at the stuffing box.

Note Adding a three ft piece of stem below the jars may help improve the sensi-tivity of seeing the jars open on the weight indicator.

It is not uncommon to run a gauge cutter into a flowing well prior to doing a flowing bottom hole pressure survey or other procedure that requires that the well remain flowing. If this is required, ensure that sufficient stem is added to allow the tools to fall. A no-blow anti-blowup tool may be used if deemed necessary to prevent the tools from being blown up the hole.

CAUTION Do not run a knuckle joint just below the jars when running a gauge cutter in a well with slide pocket gas lift mandrels, because the gauge may go into the pocket. Incorporate 3 ft of stem between the knuckle joint and jars.

b. Visually inspect the bottom of the gauge cutter for egging, and any burrs that might be on the tool; dress if necessary with a file, and not any preexist-ing marks.

c. Ensure that wireline valve and lower section of lubricator have sufficient ID and length to cover (lubricate) the gauge cutter.

d. Make up the gauge cutter onto the tool string and at the tubing hanger.

e. Raise, install, and pressure-test the lubricator and wireline valve per cus-tomer requirements.

f. Run in hole (RIH) slowly with the gauge cutter to target depth to ensure that it will not get stuck if an obstruction or restriction is encountered. If the gauge cutter reaches the target depth, pull it back out of the well. It may then be assumed that there are no obstructions in the wellbore and other service oper-ations can continue.

CAUTION Always proceed with caution when making the first trip in a wellbore that has not been entered into for some time.

g. Should the gauge cutter sit down, pick the tool string up approximately 30 ft/10m and run back in slowly. Repeat 3 or 4 more times until the gauge cut-ter falls past the obstruction or restriction, and record this depth.

h. If the tools continue to sit down, attempt to jar through the obstruction by jarring down lightly approximately 4 to 6 times. Pick up the tool string after 2 or 3 downward jars to ensure that the gauge is not becoming stuck.

i. If still unsuccessful, pull the tools out of the hole and check the gauge cutter for clues: debris such as paraffin, scale, sand, or damage to the sharp edge of the gauge cutter. Check the well schematic to determine if a component made up in the tubing string is at or near the depth of the obstruction or restriction.

j. Use findings from the gauge cutter run to determine the next course of action and tool selection.

Note If the bottom of the gauge cutter is marked up or scared up significantly, this might be an indication of an obstruction in the wellbore. If this is the case, then the next run should be with an impression block to try to further analyze what the problem might be. If there are no significant marks on the gauge cutter this indicates that there may be a restriction in the well bore. In this case, by run-ning consecutively smaller OD gauge cutters the size of the restriction may be determined and the job might still be accomplished by using a smaller OD set of tools.

Optional Tool: A swaging tool may be used. The elimination of the sharp shoulder may allow the tool to pass.

WARNING A well that has experienced a sudden drop in surface pressure may be an indica-tion that the tubing had bridged over with sand or some other obstruction that could be knocked loose when running the gauge. If this is suspected, pressure up on the well to the anticipated shut-in tubing pressure prior to running the gauge cutter or incorporate an anti-blow/no-blow tool with the gauge cutter tool string. This will help eliminate the potential for getting blown up the hole.

Debris/Deposit Removal (Cutting the Well)1. When using a gauge cutter to cut paraffin or scale from the tubing wall, it is

recommended that the well be cut while flowing to help remove the material from the wellbore. Choke back the flow on surface using an adjustable choke or some other means. Ensure that enough stem weight is added to overcome well flow past the tool string and friction acting on the wire at the stuffing box.

2. Rig up as above and run in the hole until the deposit (scale, paraffin, etc.) is encountered. Allow the tools to sit down and the jars to close.

3. If cutting paraffin, allow the tool weight of the tools to carry the gauge cutter in the hole. Spool off line occasionally as the tools fall. On scale and hard par-affin deposits it may be necessary to jar down with the gauge cutter to chip or cut away the deposit.

4. Pick up above the deposit and allow the flow of the well to clean up the tools occasionally while chipping scale and cutting paraffin. This will prevent the potential of plugging up the gauge cutter with debris.

CAUTION If the cuttings or deposits bridge across the ID of the gauge cutter, there is a possi-bility that the tool string may get blown up the hole. Occasionally pull the tools up above the deposits and let the well flow clean off the tools. In situations where hard or major deposits are present, it might be necessary to pull the tools from the well to clear them off.

CAUTION Scale that is hard set to the tubing wall can cause the gauge cutter to become stuck in the tubing. The use of a broach is recommended for scale.

CAUTION Use extreme care if scale or paraffin is encountered before the toolstring clears the tree valves as the toolstring could become stuck across tree and wireline BOPs.

Table 1:

Item Number Description OD Length

65 G 2 Gge Cutr 2.34 x 1.750 15/16-10 2.34 9.50

65 G 3 Gge Cutr 3.00 1 1/16-10 UNS 2.90 9.51

65 G 4 Gge Cutr 1.719 15/16-10 UNS 1.71 9.51

65 G 7 Gge Cutr 1.906 x 1.375 15/16-1 1.90 9.51

65 G 11 Gge Cutr 2.34 x 1.750 15/16-10 2.34 9.50

65 G 14 Gge Cutr 1.59 x 1.187 15/16-10 1.59 8.00

65 G 15 Gge Cutr 2.19 x 1.750 15/16-10 2.19 9.50

65 G 16 Gge Cutr Spec 2.00 15/16-1 1.78 9.63

65 G 17 Gge Cutr 1.91 x 1.000 5/8-11 1.91 8.94

65 G 18 Gge Cutr 4.00 x 1/16-10 UNS 3.84 9.54

65 G 19 Gge Cutr .97 x .750 1/2-13 .97 5.94

65 G 20 Gge Cutr 1.53 x 1.187 15/16-10 1.53 7.19

65 G 21 Gge Cutr 2.859 x 2.313 1 1/16-1 2.85 9.50

65 G 22 Gge Cutr 1.42 x 1.187 15/16-10 1.42 7.19

65 G 23 Gge Cutr 3.88 x 2.313 1 1/16-10 3.88 9.50

65 G 24 Gge Cutr 3.781 x 2.313 1 1/16-10 3.78 9.52

65 G 25 Gge Cutr 2.00 15/16-10 UNS 1.84 9.63

65 G 26 Gge Cutr 1.30 x 1.000 5/8-11 1.30 6.62

65 G 27 Gge Cutr 1.23 x 1.000 5/8-11 1.23 6.62

65 G 28 Gge Cutr 1.91 x 1.375 15/16-10 1.91 9.50

65 G 29 Gge Cutr 1.48 x 1.187 15/16-10 1.48 7.19

65 G 30 Gge Cutr 2.28 x 1.750 15/16-10 2.28 9.50

65 G 33 Gge Cutr 2.813 x 2.313 1 1/16-10 2.81 9.50

65 G 36 Gge Cutr 4.16 x 3.125 1 1/16-10 4.16 12.00

65 G 37 Gge Cutr 2.25 x 1.750 15/16-10 2.25 9.50

65 G 44 Gge Fluted 1.88 x 1.375 15/16-10 1.88 12.81

65 G 80 Gge Drift 1.06 x 24 3/8-16 1.06 24.00

65 G 86 Gge Cutr 3.95 x 2.313 1 1/16-10 3.95 9.50

65 G 87 Gge Cutr 2.724 1 1/16-10 UNS 2.72 9.51

65 G 113 Gge Posg 2.50 x 1.781 x 4.00 2.50 4.00

65 G 115 Gge Cutr 5.98 x 3.125 1 1/16-10 5.99 12.04

65 G 116 Gge Cutr 1.969 x 1.375 15/16-1 1.96 9.51

65 G 117 Gge Cutr 1.625 15/16-10 UNS 1.62 9.51

65 G 118 Gge Cutr 2.53 x 1.750 15/16-10 UN 2.53 9.51

65 G 119 Gge Cutr 3.09 x 2.313 1 1/16-10 3.09 9.50

65 G 120 Gge Cutr 2.873 1 1/16-10 UNS PIN 2.87 9.50

65 G 121 Gge Cutr 3.00 1 1/16-10 UNS ALY 2.69 9.63

65 G 122 Gge Cutr 2.63 x 1.75 15/16-10 2.63 9.50

65 G 123 Gge Cutr 3.43 x 2.313 1 1/16-10 3.43 9.50

65 G 124 Gge Cutr 3.74 x 2.313 1 1/16-10 3.74 9.52

65 G 125 Gge Cutr 5.85 x 3.125 1 1/16-10 5.58 12.04

65 G 126 Gge Cutr 3.35 x 2.313 1 1/16-10 3.35 9.50

65 G 127 Gge Cutr OD 6.059 1 1/16-10 6.05 12.04

65 G 128 Gge Cutr 5.95 x 3.125 1 1/16-10 5.95 12.04

65 G 129 Gge Cutr 4.55 x 3.125 1 1/16-10 4.55 12.04

65 G 130 Gge Cutr 3.60 x 2.313 1 1/16-10 3.60 9.79

65 G 131 Gge Cutr 4.470 OD 3.125 FN 1 1/1 4.47 12.00

65 G 132 Gge Cutr 3.85 x 2.313 1 1/16-10 3.85 9.50

65 G 133 Gge Cutr 2.745 1 1/16-10 UNS 2.74 9.51

65 G 135 Gge Cutr OD 1.18 1/2 13 1.18 5.93

65 G 136 Gge Cutr 1.33 Z 1.0005/8-11 1.33 6.62

65 G 137 Gge Cutr 1.88 15/16-10 UNS 1.88 9.51

65 G 138 Gge Cutr 1.96 15/16-10 UNS 1.96 9.51

65 G 139 Gge Cutr 2.04 x 1.375 15/16-10 U 2.04 9.51

65 G 140 Gge Cutr 2.16 x 1.375 15/16-10 U 2.16 9.51

65 G 141 Gge Cutr 2.56 x 1.750 15/16-10 2.56 9.50

65 G 143 Gge Cutr 3.07 x 2.313 1 1/16-10 3.07 9.50

65 G 144 Gge Cutr 3.14 x 2.313 1 1/16-10 3.14 9.50

65 G 146 Gge Cutr 3.62 1 1/16-10 UNS 3.62 9.79

65 G 147 Gge Cutr 3.70 x 2.313 1 1/16-10 3.70 9.79

65 G 148 Gge Cutr 6.100 x 3.125 FSH 1 1/1 6.10 12.04

65 G 155 Gge Cutr 2.89 x 2.313 1 1/16-10 2.89 9.50

Table 1:

65 G 156 Gge Cutr 3.00 1 1/16-10 UNS ALY 2.73 9.63

65 G 157 Gge Cutr 2.34 15/16-10 2.31 9.50

65 G 158 Gge Cutr 5.72 x 3.125 1 1/16-10 5.72 12.04

65 G 160 Gge Cutr 5.58 OD 1 1/16-10 5.58 12.00

65 G 161 Gge Cutr 3.310 x 2.313 1 1/16- 3.31 9.54

65 G 162 Gge Cutr 3.830 x 2.313 1 1/16 3.83 9.79

65 G 166 Drift Gge 2.797 OD x 42.0 LG 2.79 42.50

65 G 167 Gge Cutr 3.250 x 2.313 1 1/16- 3.25 9.50

65 G 169 Gge Cutr 4.70 x 3.125 1 1/16- 4.70 12.00

65 G 170 Gge Cutr 3.50 x 2.313 1 1/16- 3.50 9.50

65 G 171 Gge Cutr 3.73 x 2.313 1 1/16- 3.73 9.50

65 G 172 Gge Cutr 3.75 x 2.313 1 1/16- 3.75 9.50

65 G 173 Gge Cutr 3.80 x 2.313 1 1/16- 3.80 9.50

65 G 174 Gge Cutr 3.81 1 1/16-10 3.81 9.50

65 G 175 Gge Cutr 2.50 x 1.750 15/16-10 2.50 9.50

65 G 176 Gge Cutr 2.810 1 1/16-10 2.81 9.50

65 G 177 Gge Cutr 2.31 1 1/16-10 2.31 9.50

65 G 178 Gge Cutr 5.96 1 1/16-10 5.96 12.00

65 G 180 Gge Cutr 4.70 x 3.125 1 9/16- 4.70 12.27

65 G 181 Gge Cutr 4.470 x 3.125 1 9/16- 4.47 12.27

65 G 182 Gge Cutr 5.985 x 3.125 1 9/16- 5.98 12.27

65 G 183 Gge Cutr 5.947 x 3.125 1 9/16- 5.94 12.27

Table 1:

Otis® Gauge Cutter

Slickline Operations Manual SL 2.3: Perforator Dummy Use

SL 2.3: Perforator Dummy Use

1.0 ScopePrior to conducting electric line logging or perforating services inside or through the tubing, a dummy ran to simulate the longer and stiffer logging tools and per-forator guns is performed on the well utilizing slickline. A perforator dummy of the same size and length of logging tools or perforator gun is run in the hole to the target depth. This service is used to determine if the there are any well bore prob-lems that could potentially lead to the loss or damage of the costly logging tools or potentially dangerous perforators.

2.0 General InformationThe perforator dummy (sometimes referred to as a drift bar) is the preferred tool to use to drift the tubing in slickline operations (Figure 1). Other tools such as a bailer bottom or long sections of made-up stem may be used to drift the tubing. The perforator dummy is a long cylindrical-shaped tool that is usually made from aluminum. Perforator dummies or “dummies” come in various diameters that are common to the size of standard logging tools or perforator guns (Table 1).

Perforator dummies of short length (5ft.-15ft.), are usually made as a single piece. Longer perforator dummies (20ft.-60ft.), are made up from 5ft. long sections to achieve a length that represents that the logging tool or perforating gun to be run. Perforator dummies are used to not only gauge the ID of the tubing, but to drift it as well. In some cases the smaller length of the gauge cutter will make it down the tubing, but the longer length of the same OD such as a logging tool or perforating gun will not make it past a bend or curve in the tubing. A dummy is used to determine if the high cost logging tools or potentially dangerous explosive perfo-rator will make it to the target depth without getting hung up in the hole. The dummy is used to simulate the length, stiffness, and OD of the logging tool or perforating gun that will be run in the well later, to ensure that these tools can reach their target depth without getting stuck or damaged.

Making a dummy run on slickline prior to running a long stiff logging assembly is becoming common practice with more deviated and high angle wells being drilled. THe dummy run can help eliminate the cost and safety issues associated with damaging or attempting to fish logging tool or perforator in a well.

Always run a gauge cutter prior to running a perforator dummy, unless a gauge run or other tools of sufficient OD have been run in the well during the same project. the gauge cutter OD should be larger then the OD of the perforator dummy. The smaller length and fluid bypass of the gauge cutter, its proximity to the jars, the smaller OD of the stem, and the shorter length of the gauge cutter tool string assembly make it the desired tool to run in the hole prior to the longer per-forator dummy. The gauge cutter tool string assembly is easier to jar loose from any well debris encountered and is also relatively easy to fish, if it is left in the hole.

Slickline Operations Manual SL 2.3: Perforator Dummy Use

Do not run gauge on the bottom of a perforator dummy. Some customers may request that this be done to eliminate a slickline run into the well. The larger OD of the gauge cutter will be the most likely point that could get lodged or stuck in the wellbore. The length and OD of the perforator dummy with gauge is left in the hole, an extremely tall lubricator stack may be required to get it out if the well is not dead.

3.0 Procedure1. Ensure that proper length and OD of perforator dummy is selected (Table 1).

The perforator dummy should be as long as the logging tools or perforator that is to be run and must be the same OD or slightly larger if the same OD dummy is not available. If the perforator dummy is to be run in a flowing well, ensure that enough stem weight is added to overcome well pressure and flow friction acting on the dummy and tool string.

2. Make up sufficient lubricator stack with the appropriate ID to cover the length and OD of the perforator dummy and tool string. Test the same in accordance with customer requirements.

3. Select and run an appropriate-sized gauge cutter for the job. Note fluid levels, tight spots and location of any increased drag when coming out of the hole.

4. Make up the perforator dummy assembly to the desired length and attach it to a tool string consisting of spang jars, at least 5 ft. of stem, knuckle joint, and rope socket.

Note To ease makeup and removal of the perforator dummy, it is recommended that a quick disconnect be used below the jars. The stem and jars are used to facil-itate getting the dummy loose if it gets wedged into a tight spot or crooked tub-ing. Consider the use of a pulling tool with a rope socket attached to the dummy.

5. Run in hole (RIH) to target depth slowly, making periodic pickups to deter-mine pickup weight on tool string and pull out of the hole.

6. Proceed with caution through those areas identified by the gauge cutter run as tight spots or areas of increased drag. Get pickup weights more frequently in these intervals.

7. If it appears that the drag is continuing to increase and is approaching the safe working tension of the wire, then pull the dummy from the well. Note the amount of drag (over-pull) required to get tools moving and the interval where this drag occurs.

8. If the perforator dummy sets down, get a pickup weight. If no appreciable increase in a drag has taken place, then jar down slightly to see if the tools will fall through the restriction. Pick up after every downward jar to ensure that tools are not getting stuck. If the tools don’t fall, pull out of the hole.

9. Visually inspect the perforator dummy for wear marks that might give an indication as to what may have been encountered. Review the well schematic to determine if there is a reason such as cork screwed tubing, buckled tubing, a tight spot, etc.

10. Based on the perforator dummy run, determine next course of action.

Slickline Operations Manual SL 2.4: Swaging Operations

SL 2.4: Swaging Operations

1.0 ScopeMinor restrictions or tight spots in the production tubing string resulting from mishandled tubing can usually be opened up to allow passage of flow controls by performing a swaging operation with slickline.

2.0 General InformationSwaging operations are limited to minor restrictions such as mashed pipe and over-torqued tubing and should not be attempted when damage to the tubing is severe. Swaging operations are normally performed after several attempts have been made to run smaller size gauge cutters through a tight spot in the tubing. An impression block may also be run to determine the extent of damage.

The tool used to perform swaging operations is called a swaging tool (fig. 1). The swaging tool is tapered on both ends. The upper part of the tool incorporates the standard tool string thread connection with fish neck. The tool also contains a fluid bypass. Swaging tools are available for several sizes of tubing or can be cus-tom-made to meet the dimensional requirements for a specific job. Swaging tools may also be used to gauge the tubing prior to running plugs and other devices.

3.0 Procedure1. Determine the largest ID of the tight spotting in the tubing by running consec-

utively smaller gauge cutters and record the largest size that made it through. (See SL 1.22 Gauging the Well)

2. Select the largest swaging tool with an OD that will drift any nipple encoun-tered, but be slightly larger than the OD of the gauge cutter that made it through the tight spot.

CAUTION The OD of the swage should not exceed the ID of any landing nipples that may be encountered, because the tool could become wedged into the nipple.

3. Make up the swaging tool on the end of a tool string, run in the hole, and jar down on the tight spot. Jar up on the tool string occasionally until the tools pull fee to ensure that the swaging tool is not getting wedged into the tight spot.

4. When the swaging tool falls through, pull backup into the tight spot and jar up until the tool comes free. Repeat jarring down and up through the tight spot as necessary until the tool moves freely without hanging up.

5. Repeat the above operations as necessary with consecutively larger swaging tools until the desired ID through the tight spot in the tubing is achieved.

Slickline Operations Manual SL 2.4: Swaging Operations

CAUTION When swaging at shallow depths with no fluid, a heavy bouncing tool string may cause the wire to pull out of the rope socket. Consider the use of an accelerator.

Note Wire fatigue above a no-knot type rope socket during heavy jarring may be reduced by placing a knuckle joint between the rope socket and top piece of stem. The knuckle joint allows the wire to flex freely, thus eliminating the poten-tial for fatigue.

CAUTION Excessive stem weight might cause the swage to get stuck rather than changing the ID of tubing.

4.0 AppendixC

Otis® Swaging Tool

Slickline Operations Manual SL 2.5: Broaching Operations

SL 2.5: Broaching Operations

1.0 ScopeSlickline broaching operations are used to remove burrs, rust, scale and other types of hard buildup in the production tubing string to ensure the passage of flow controls into and out of the wellbore.

2.0 General InformationTubing broaches, run on slickline, are used to:

• Remove mill scale, mineral scale, and of other hard deposits from the tubing wall.

• Remove metal burrs from the tubing ID.• Remove internally extruded metal from the tubing connection (where exces-

sive torque has been applied).

• Enlarge the ID of various undersized components that may have been installed as part of the tubing string.

Tubing broaches are available in several different designs and used for specific applications.

Segmented BroachThis type of broach consist of a carrier mandrel, nut, and three (3) broaching spools/segments with helical-type cutting surfaces (figure 1). This broach is used primarily to remove mill scale and other deposits on the tubing walls prior to installation of a plunger lift system. It can also be used for cleaning up long intervals inside of tubing where buildup or scale is not severe. Segments and mandrels are available in various tubing sizes from 1 1/4 in. through 4 1/2 in. (table 1). This broach should always be run with two lower segments pointed down and the upper segment pointed up.

Diamond BroachDiamond broaches contain raised and hardened diamond-shaped cutting surfaces (fig-ure 2). They are used primarily to remove metal burrs and short intervals of light scale buildup.

Note Do not use around or near landing nipples or packing/polished bores.

Pineapple BroachThe raised cutting surfaces on this broach are more square shaped and protrude further away from the body to allow for more fluid bypass (Figure 3). This broach is used to remove metal burrs, and for moderate scale build up from mineral deposits over long intervals.

Tapered BroachThis type of broach resembles a swage with hardened tapered cutting edges. It is used primarily for removing metal burrs, etc., from very short intervals in the tubing (figure 4). Tapered broaches are also available with diamond- and pineapple- shaped cutting surfaces.

Paddle BroachThis broach contains hardened paddles/blades that have been welded to a relatively small OD mandrel (figure 5). This broach is used to remove heavy mineral scale deposits from the tubing walls over long intervals. This paddle broach is ideal for this purpose as it has sufficient fluid bypass to allow removal of scale while the well is flowing.

CAUTION Cut the up-facing tip off of the top blades to eliminate the possibility of them hanging at the end of the tubing or the bottom of seal assemblies that may be encountered in the completion.

Before running a broach, the minimum ID of the tubing restriction that is to be enlarged must be determined. Then a broach that is slightly larger then the restriction is used to begin enlarging the ID of the restriction. Once the initial broach moves freely through the restriction is used to begin enlarging the ID of the restriction. Once the initial broach moves freely through the restriction, the next larger-sized broach is used. This process is repeated until the restric-tion is cleaned or a desirable ID is reached.

3.0 Procedure1. Determine the largest ID of the tight spot in the tubing by running consecu-

tively smaller gauge cutters, and record the largest size that made it through (see WL 2.2 Gauging Operations).

2. Select the desired broach depending on the application outlined above. Select a broach with an OD that will drift any nipples encountered, but be slightly larger then the OD of the gauge cutter that made it through the tight spot. Consideration should be made for shutting in the well or flowing the well during broaching operations.

n Shut in the well when broaching short metallic restrictions. This is most important when using a serrated tapered broach as it may get wedged in the tubing. With the diamond broach the fluid bypass channels may become clogged with paraffin or scale. In either case, the tools can be blown up the hole if the broach restricts the flow of the well long enough to create a differential pressure that will overcome the weight of the tool string.

n Flow the well when using pineapple and paddle broaches with large fluid bypass during scale removal operations. It is recommended that an adjustable choke be used during this process to control the flow. In addi-tion, check the broach periodically to ensure that the fluid bypass areas are not becoming clogged.

CAUTION The OD of the broach should not exceed the ID of any landing nipples that may be encountered as the tool could become wedged into or damage the nipple.

CAUTION When selecting a broach to remove scale, check broach for fluid bypass through center.

3. Make up the broach on the end of a tool string, run in the hole, and jar down on the tight spot. Jar up on the tool string occasionally until the tools pull free to ensure that the broaching tool is not getting wedged into the tight spot.

4. When the broach falls through, pull back through or into the tight spot and jar up until the tool comes free. Repeat jarring down and up through the tight spot as necessary until the tool moves freely without hanging up. When broaching mineral scales it is recommended that the tools be pulled back above the scale deposit periodically to clear away buildup of debris on the tool. Also, the broach should be pulled on occasion for cleaning and inspec-tion during heavy extended scale removal operations.

5. Repeat the above operations as necessary using consecutively larger broaches until the desired ID through the tight spot or scale deposits are achieved.

CAUTION When broaching at shallow depths with no fluid, a heavy bouncing tool sting may cause the wire to pull out of the rope socket.

Note Wire fatigue above a no-knot type rope socket during heavy jarring may be reduced by placing a knuckle joint between the rope socket and top piece of stem. The knuckle joint allows the wire to flex freely, thus eliminating the poten-tial for fatigue.

4.0 Appendix

Otis® Tubing Broach

Slickline Operations Manual SL 2.6: Use of Impression Blocks

SL 2.6: Use of Impression Blocks

1.0 ScopeAn impression block is a tool that is used in wireline operations to help identify obstructions and restrictions in the wellbore. An impression block helps to iden-tify these problems by taking an impression of the object. The block can then be used to determine the proper fishing tool to try to build and remove the debris or restriction in the wellbore.

2.0 General InformationAn impression block is the primary diagnostic tool used in wireline operations to identify problems downhole. It performs its function by taking an impression block contains a very soft malleable alloy to receive and hold the impression of what it encounters. The alloy is poured into the tool in a molten state and allowed to cool with approximately 3/4 in. to 1 in. of the alloy protruding out the bottom of the tool.

Note Re-pour or replace the impression block once the alloy is down to within 1/4 in. of the impression block housing.

Note Insure that alloy retainers are in place and secure to prevent the alloy from falling out of the housing into the wellbore.

3.0 Procedure1. Select and run the proper-sized gauge cutter for the relevant tubing size and

nipple sizes.

2. If an obstruction or restriction is encountered on the gauge run, an impression block should be run next.

3. Select the proper-sized impression block for the job, relevant to tubing and nipple sizes.

4. Dress up the impression block to remove all imperfections.

Note A ball-peen hammer and rasp file are most commonly used. Leave enough lead on the bottom of the impression block to get the desired impression.

5. Zero the tool string prior to making an impression block up on the tool string to avoid possible marking of the impression block while zeroing.

6. Run in the hole at approximately 250-300 ft/min. Slow down when encounter-ing nipples, gas lift side pockets, crossovers, etc.

Note Make pickups frequently while running to insure that the impression block is still moving freely. The impression block has no fluid bypass and there is potential that debris could fall on top of it and make it difficult to remove from the wellbore.

Slickline Operations Manual SL 2.6: Use of Impression Blocks

7. Stop at point above the obstruction or restriction and get a pickup weight. Pro-ceed in the hole at approximately 100ft/min and set down. Allow the jars to close and avoid bouncing the jars.

Note If jars are sluggish, hit down two or three times.

CAUTION Care should be taken not to flare out the lead or knock the lead off of the impres-sion block by jarring down too hard.

8. Use the markings on the impression block to determine the next course of action. In some cases running various sizes of impression blocks may better identify the problem.

Note To make a copy of the impression, use an ink pad to apply ink to the bot-tom of the impression block. Then press the impression block against a clean sheet of paper that is supported underneath with a thin rag or cloth. This helps in applying the ink to the paper. This creates a fairly nice picture of the bottom of the impression block that can be faxed to other locations for further analysis and can be used for marking special fishing tools.

Note Loose sand, scale, and paraffin will not make much of an impression; a bailer might be consider as the next possible run.

4.0 Appendix

Otis® Impression Tool

Slickline Operations Manual SL 2.7: Paraffin Cutting and Scale Removal

SL 2.7: Paraffin Cutting and Scale Removal

1.0 ScopeParaffin cutting and scale removal are done to ensure proper flow of well fluids. Removal of paraffin and/or scale may need to be performed prior to running or pulling any wireline-retrievable flow control device (locks, plugs, safety valves, etc).

2.0 General Information1. Paraffin and scale can both hinder well flow and the ability to maneuver

downhole. Paraffin is the result of a waxy buildup of dehydrated hydrocar-bons. Scale results from mineral deposits on the tubing bore.

2. Paraffin cutting and/or scale removal is done by the use of wire scratchers and paraffin cutters.

3.0 Procedure1. Paraffin cutting and scale removal well shut in.

a. Select the proper size paraffin scratcher, knife, or cutter for the relevant tub-ing size and weight. Consider paraffin/scale type and density.

Note Adding a three foot piece of stem below the jars may help reduce the risk of jars becoming fouled with paraffin/scale.

b. Make up the cutter, knife, or scratcher onto the tool string and tubing hanger.

c. Raise into lubricator and make up lubricator to the wellhead. Pressure-test if necessary per customer requirements.

d. Open the wellbore and slowly go in the hole with the cutter, knife, or scratcher to target depth. Allow the tool weight to carry the tools in the hole. Feed off-line as necessary. On hard paraffin or scale, it may be necessary to jar down with tools to remove paraffin/scale.

e. Continue working the tool downhole, removing as much paraffin/scale as possible without getting stuck.

f. Pull the tools back to the surface.

g. Close the swab valve. Open the wing valve and flow the well, removing paraffin/scale that was cut loose.

h. Shut the well in with the wing valve.

Slickline Operations Manual SL 2.7: Paraffin Cutting & Scale Removal

i. Open the swab valve, repeat steps until the wellbore is clean.

CAUTION Care should be taken if the toolstring has not cleared the wireline BOPs and tree when the paraffin or scale is encountered.

2. Paraffin cutting and scale removal well flowing.

a. Ensure that enough sinker bar is added to the tool string to allow the tools to overcome the flow rate past the tool string and friction acting on the wire at the stuffing box.

b. Start with a smaller scratcher/knife to allow fluid bypass.

c. Choke back the flow rate on the surface using an adjustable choke or some other means and monitor the flow rate during operations.

d. Follow steps in the shut-in procedure.

e. Pick up above paraffin/scale and allow the well to flow, cleaning up the tools occasionally. This will help theprevent tools from plugging with paraf-fin/scale.

f. Continue until the wellbore is clear of paraffin/scale.

CAUTION Cutting paraffin may cause a plug or ball and there is a possibility that the tool string may get blown up the hole. Occasionally pull up above the paraffin/scale buildup and allow the well to flow, cleaning up the tools. In hard, thick paraffin the tool string may need to be removed from the wellbore and cleaned on the sur-face.

Slickline Operations Manual SL 2.8: Selection and Use of Flow Controls

SL 2.8: Selection and Use of Flow Controls

1.0 ScopeA flow control device is any device set in a nipple or in the tubing to control the flow of the well, (safety valves, storm chokes, plugs, standing valves, downhole chokes, etc.).

2.0 General Information• The proper flow control assembly should not be determined by the relevant

wellbore conditions and type of operation to be accomplished. All flow con-trols should be rated for the maximum differential pressure to be seen at the depth the plug is set.

• Positive plug should be run when the objective is to hold pressure from above and below (ex. plug-backs, testing tubing, etc.).

• Pump-through plugs should be run when you want to have the ability to pump through the plug to kill the well in case of emergencies.

• An equalizing device or equalizing sub should always be run in conjunction with a flow control device.

• Tubing pressure and fluids should always be noted when setting plugs for proper equalization when pulling those plugs.

• A check-set should always be run to verify proper setting of the lock when and where applicable.

3.0 Procedure1. For determining the proper assembly to be run, obtain all relevant informa-

tion from the well schematic, last well test, BHP, prior W.L logs.2. Verify that the flow control has the proper pressure rating

3. Always shut the well in when pulling and running flow controls to avoid get-ting blown up the hole.

4. Always run a gauge cutter prior to running or pulling the flow control. This help ensure that the flow control can be run safely in the wellbore. The gauge cutter should be .010 in.under the nipple or retrieved from ID that the flow control is to be seated in.

Slickline Operations Manual SL 2.9: W Slip Lock System

SL 2.9: W Slip Lock System

1.0 ScopeA means of anchoring a flow control in the wellbore without using a nipple.

2.0 General Information• The pressure rating on W slip-type mandrels is 1,500 psi.

• Has serrated slip which anchor into the tubing wall, and has a large rubber element instead of a packing stack.

3.0 Procedure1. Can be run on a W running tool or a friction tool (provided the expander pins

are removed) and is pulled with RB, BB, or UO.2. Gauge run should be made prior to running the W mandrel.

3. See attachment for running and pulling procedure.4. Always set the W mandrel a minimum of 100ft. below mud line. This is so that

in case you can’t retrieve it, you can still P & A the well without moving a ring on location.

CAUTION Do not use a pulling tool with has a longer reach than the type “RB” or type “BB” pulling tools. Tools with a longer reach will not unlock the type W mandrel.

Do not sit back down on W mandrel while setting it. It may unlock the mandrel and let it fall downhole.

Do not use a shear-down-to-release pulling tool as the pin might shear when jar-ring down to unlock.

Slickline Operations Manual SL 2.10: D Collar Lock System

SL 2.10: D Collar Lock System

1.0 ScopeThe Type D Collar Lock is designed to lock in any collar recess of EUE or NU tub-ing.

2.0 General InformationThe Type D Collar Locks are retrievable and easy to run. They are only used in standard-weight 8 round tubing, and can be set in any collar in the tubing. They are generally use as DD bridge plugs, a lock for a safety valves, and are rated for 5,000 psi., depending on the condition of the tubing. The type D collar lock has an internal mandrel. When pulled up into a tubing collar, the internal mandrel’s keys latch and the internal sleeve sides up and locks into place.

3.0 ProcedureRunning & Pulling of type D collar locks1. Make a gauge run to the desired depth.

2. Run type D collar lock down below the desired depth, then pick up to the next collar. The keys will automatically locate into the collar recess.

3. Set by upward jarring. Once you have sheared off, do not sit back down on the D collar lock, since the running tool can unlock the D collar lock by hitting the internal sleeve, causing the sleeve to move down and unlock the keys. Oil jars can be used as an option for setting.

Note The GRL is the only pulling tool that should be run in pulling a Type D Collar Lockout. The GRL pulling tool has an elongated core that goes into the D collar lock and recesses into the internal sleeve. Hitting down on the internal sleeve will cause the sleeve to move down and unlock the keys. The GS pulling tool will latch the D collar lock but will not unlock it. The internal sleeve must be pushed down in order for the keys to move inward for the lock to unlock.

Slickline Operations Manual SL 2.11: S, N, & T, Q Equipment

SL 2.11: S, N, & T, Q Equipment

1.0 ScopeThis equipment is profile selective, used to lock flow controls in the wellbore.

2.0 General Information1. This equipment is simpler to run due to the fact that it will only set in the pro-

file it is supposed to.2. This equipment has an external F/N.

3. By changing only the keys and/or the inner mandrel, you can lock in any pro-file in the wellbore. (ex. pos.1 - pos. 7)

4. S equipment is for standard weight tubing made up of lock and locator man-drel(s).

Note V equipment is same as S equipment, but has a larger packing bore. It is normally set higher in the well for swabbing purposes.

5. N equipment does not require a locator mandrel as it no-go’s in the nipple.

6. T equipment is the same as S equipment. It is built for heavy wall tubing, and has a smaller packing bore I.D. It is only used in pos. 1-5 nipples, but does not have a higher pressure rating.

7. Q equipment is the same as N equipment. It is built for heavy wall tubing and it no-go’s in the nipple, but does not have higher pressure rating.

3.0 Procedure1. A gauge run should be made prior to running and/or pulling S, N, T, and Q

equipment.2. After verifying that the tubing is free of obstructions or restrictions, the proper

running prong is attached to the T running tool (primary R/T). The running prong is used for fluid bypass when running in hole.

3. See attachment for running and pulling procedure for S, N, T and Q equip-ment.

4. Pinning of this equipment depends on many variables.

n In heavy fluid or mud, light pins (brass or aluminum) are adjustable due to inhibited jar action. If you have to work through any restrictions, steel pins are advisable to stop from shearing pins before setting lock.

5. This equipment must be equalized fully before you can latch due to the design of this equipment.

6. In the event that you are unable to use the T running tool, an alternate running tool is the J running tool. If this running tool is used, no pickups can be made, as the locking keys’ clogs will not allow you to do so.

Slickline Operations Manual SL 2.12: X - XN & R - RN Equipment

SL 2.12: X - XN & R - RN Equipment

1.0 ScopeX, R, XN & RN equipment are flow control equipment used to control wellbore pressure at predetermined depths.

2.0 General InformationThe type X & R running tools are used to run and set X, R, XN & RN locking man-drels & subsurface controls in their respective tubing landing nipples. These run-ning tools may also be used to located existing X & R landing nipples. These nipples can also be used as a measure of depth correlation to other W/L measure-ments and tubing details.

3.0 Procedure1. Following gauging operation 2.2.

2. Select the proper X & R and XN & XR equipment.3. Select the proper size X, R, XR, & RN equipment for the relevant tubing size

and nipple size. Ensure that stem weight is enough to over come the well pres-sure and friction acting on the wire at the stuffing.

4. The corresponding running tool should be made up to the desired X, R, XN & RN locks, and placed in the select position.

5. Ensure that the wireline valve and the lower section of the lubricator have suf-ficient length and bore to cover “lubricate” the selected equipment.

6. Make up X, R, XN & RN equipment onto the tool string.7. Raise into the lubricator and make up the lubricator to the wellhead. Pressure-

test if necessary per customer requirement.8. Open the well-bore and go in hole with equipment.

9. Proceed down into wellbore until the desired landing nipple is located. 10. Next, lower the running tool & lock through the nipple approximately. five to

six feet.11. Raise the tool string back through the nipple.

12. An approximate 200 lb strain (bind) is recommended to pull the running tool up through nipple.

13. Now, with the lock/running tool in the control position, lower back down into the nipple to set the lock.

14. Use downward jarring action to shear the top pin in the running tool.

15. Pull an upward strain of approximately. 200 lb to confirm that the lock man-drel has been set.

Slickline Operations Manual SL 2.12: X - XN & R - RN Equipment

16. After confirmation, upward jarring action will shear the bottom pin, separat-ing the running tool and the lock mandrels, allowing the running tool and tool string to return to the surface.

Note The no-go restriction designed into the types ‘XN’ and ‘RN’ Landing Nip-ples will not allow the equalizing valve body attached to the RN lock mandrels. The running tool must be placed in the control position before reaching the land-ing nipple. This must be either be done by hand at the surface, or the running tool may be positioned to the control position in a type ‘X’ or ‘R’ landing nipple (or proper ID packing nipple) located in the tubing above the No-Go nipple.

As the lock mandrel reaches the no-go shoulder in the landing nipple, the tool string will stop, and the lock mandrel may be set in the same manner as types ‘X’ and ‘R’.

If the operator is unable to locate in the nipple with the lock mandrel, after going through the procedure to places the running tool in the control position, there are several things that could cause this:

• There could be weak double-acting key springs on the lock mandrel.

• There could be worn shoulders on the running inner mandrel, or the locating dogs, or both. If these shoulders are worn off the tool cannot be kept in the control position.

• The bottom pin in the running tool may be sheared. If there has been any upward jar action as the tool passes the nipple restrictions above, the bottom pin in the running tool may have been sheared.

4.0 AppendixReference - 2.2 Gauging the Well

Slickline Operations Manual SL 2.13: RPT Lock System

SL 2.13: RPT Lock System

1.0 ScopeThe Halliburton RPT Lock Mandrel is a high pressure rated top no-go lock system for plugging applications. The lock mandrel is designed to land and lock subsur-face flow controls in a RPT landing nipple profile only. It is designed to hold pres-sure differentials from above or below and is installed and retrieved by standard wireline methods.

2.0 General InformationThe RPT Lock Mandrel is run with a Halliburton RXNTM Running Tool in the retracted position. The running tool is attached to the lock mandrel and shear pinned. This places the expander sleeve in the fully extended position. When the expander sleeve is fully extended, the key springs bias the keys in to the retracted position. With the keys retracted, the lock mandrel can be lowered and landed on the No-Go shoulder at the top of the landing nipple hone diameter.

Once landed, downward jar action shears the top shear pins in the running tool, which permits the expander sleeve to move down beneath the keys to the fully locked position.

When locked, upward jar action checks to determine if the lock is locked and shears the lower shear pin to release the running tool from the lock mandrel.

RPT locks have either a shear pin hold-down or interference hold-down feature. The shear pin hold-down locks the expander sleeve and the key retainer together when the lock is fully set. The pins must be sheared to pull the lock. The interfer-ence hold-down locks the expander sleeve and the packing mandrel together with an interference fit when the lock is fully set. These hold-downs inhibit the lock mandrel from being flowed from the landing nipple.

CAUTION Do not attempt to run the lock mandrel with the running tool in the locate position (keys biased outward). The lock mandrel expander sleeve will extend under the keys and will not permit the keys to fully retract when the running tool is in the locate configuration.

Note For specific design information on this lock mandrel assembly, refer to the appro-priate Design Specification Data (DSD).

3.0 ProcedureInstallation Procedure

Note This procedure is for when a RXTM or a RXN non-selective running tool is used.

Attach the lock mandrel to the running tool in the no-go or fully extended posi-tion as prescribed in the running tool’s Basic Design and Maintenance Instructions (BDMI).

To ensure proper operation of both the running tool and the lock mandrel, the fol-lowing should be checked:

1. The keys of the lock mandrel should be fully retracted.

CAUTION Do not attempt to run this lock mandrel in the locate position.

2. The lower shear pin should be thoroughly bradded and cross center punched to ensure that it stays in place during the running operation.

3. The shear pin should be filed flush with the outside diameter of the packing mandrel.

4. Make up the lock mandrel and the running tool assembly on a standard wire-line tool string.

5. Lower the tool string into the tubing until the RPT landing nipple is located.6. Continue lowering the tool string until the lock mandrel no-go lands on the

no-go shoulder of the landing nipple.7. Jar down hard to shear the upper shear pins in the running tool and lock the

lock mandrel in the nipple.

8. Test the lock mandrel by applying an upward strain on the wireline. If the mandrel is properly locked in the nipple, upward jarring shears the lower pin in the running tool and allows the tool string to be returned to the surface.

9. If the mandrel is not properly locked in the nipple, it should jar loose before the lower pin is sheared. If this should happen, lower the mandrel back into the nipple and repeat Step 7.

RetrievingThe GR Pulling Tool is recommended to retrieve the RPT Lock Mandrel. The GS Pulling Tool may be used as an alternate as outlined below.

Note The proper pulling prong should always be used with the pulling tool and adequate time for equalization should always be allowed before jarring upward on the lock mandrel.

1. Make up the proper size prong into the bottom of the pulling tool and attach the pulling tool to a standard wireline tool string.

2. Lower the tool string into the bore of the tubing until the lock mandrel is con-tacted.

3. As the pulling tool enters the lock mandrel, the prong ensures that the flow control device is placed in the equalizing position. (A slight downward jar action may be necessary to shift the valve.)

4. The weight of the tool string should be allowed to rest on the lock mandrel while pressure across the subsurface flow control device is being equalized.

5. After equalization has been confirmed, an upward strain on the wireline indi-cates whether or not the pulling tool is latched into the fish neck of the lock mandrel.

6. Jar at least one firm stroke downward on the lock mandrel to loosen the lock mandrel in the nipple.

7. Place an upward strain on the wireline. In most cases, this is all that is required to move the expander sleeve up, allowing the keys to retract and extract the lock mandrel from the landing nipple.

8. In some cases, upward jar action may be necessary to extract the lock mandrel.

9. If the pin in the GR pulling tool shears without pulling the lock mandrel, then a GS Pulling Tool can be used.

CAUTION Do not make up a pulling prong into the GS Pulling Tool when retrieving a lock mandrel with an RPT Equalizing Valve attached. Any attempt to jar down and shear off will be obstructed by the pulling prong and cause damage to the pulling prong or the equalizing valve.

Slickline Operations Manual SL 2.14: RPV Lock Mandrel

SL 2.14: RPV Lock Mandrel

1.0 ScopeThe RPV lock mandrel is a modified version of the RPT lock mandrel. It is designed primarily for the installation of subsurface safety valves in RPT landing nipple profiles.

2.0 General InformationThe RPV lock mandrel is run with a Halliburton RXN Running Tool. The running tool is attached to the lock mandrel and is shear pinned. This places the expander sleeve in the fully extended position. When the expander sleeve is fully extended, the key springs bias the keys into the retracted position. With the keys retracted, the lock mandrel can be lowered and landed on the no-go shoulder at the top of the landing nipple hone diameter.

Once landed, downward jar action shears the top shear pins in the running tool, which permits the expander sleeve to move down beneath the keys to the fully locked position. When locked, upward jar action checks to determine if the lock is locked and shears the lower shear pin to release the running tool from the lock mandrel.

The lock mandrel has matching nonhelical teeth inside the keys and on the OD of the expander sleeve, which engage and become the primary hold-down when the lock is sub-jected to a pressure differential from below. This primary hold-down inhibits the lock mandrel from being flowed or pulled from the landing nipple when a pressure differential exists from below.

3.0 Procedure

Installation(When RX or RXN nonselective running tool is used)

Attach the lock mandrel to the running tool in the no-go or fully extended posi-tion as prescribed in the running tool’s basic design and maintenance instructions.

• The keys of the lock mandrel should be fully retracted.• The lower shear pin should be thoroughly bradded and cross-center punched

to ensure that it stays in place during the running operation.• The shear pin should be filed flush with the outside diameter of the packing

mandrel.

1. Make up the lock mandrel and the running tool assembly on a standard wire-

Slickline Operations Manual SL 2.14: RPV Lock Mandrel

line toolstring.

2. Lower the toolstring into the tubing until the RPT landing nipple is located.3. Continue lowering the toolstring until the lock mandrel no-go lands on the

no-go shoulder of the landing nipple.

4. Jar down hard to shear the upper shear pins in the running tool and to lock the lock mandrel in the nipple.

5. Test the lock mandrel by applying an upward strain on the wireline. If the mandrel is properly locked in the nipple, upward jarring shears the lower pin in the running tool and allows the toolstring to be returned to the surface.

Note If the mandrel is improperly locked in the nipple, it should jar loose before the lower pin is sheared. If this should happen, lower the mandrel back into the nipple and repeat Step 4.

RetrievingThe GR pulling tool is recommended to retrieve the RPV lock mandrel. The GS pulling tool may be used as an alternate as outlined below.

Note The proper pulling prong should always be used with the pulling tool, and adequate time for equalization should always be allowed before jarring upward on the lock mandrel.

1. Make up the proper size prong into the bottom of the pulling tool and attach the pulling tool to a standard wireline toolstring.

3. As the pulling tool enters the lock mandrel, the prong ensures that the flow control device is placed in the equalizing position. (Slight downward jar action may be necessary to shift the valve.)

4. The weight of the toolstring should be allowed to rest on the lock mandrel while pressure across the subsurface flow control device is being equalized.

5. After equalization has been confirmed, an upward strain on the wireline indi-cates whether the pulling tool is latched into the fish neck of the lock mandrel.

7. Place an upward strain on the wireline. In most cases, this is all that is required to move the expander sleeve up, allowing the keys to retract and extract the lock mandrel from the landing nipple.

Slickline Operations Manual SL 2.15: SAFETYSET® Lock System

SL 2.15: SAFETYSET® Lock System

1.0 ScopeThe SAFETYSET® lock mandrel system is a drive-down, jar-up-to-lock, no-go-type lock mechanism designed specifically for wireline-retrievable surface-con-trolled subsurface safety valve applications.

2.0 General InformationThe running tool is attached to the lock and safety valve. The piston of the valve is dis-placed by the core of the running tool. The spring force from the displaced piston is trans-ferred to the dog retainer through a pin that ties the core and the dog retainer together. The dog retainer is held in place by the retaining dogs engaged in the lock mandrel fish neck profile. The retaining dogs are maintained in the profile by support of the lower setting sleeve.

The toolstring is attached to the running tool through the top sub. The top sub is releas-ably connected to the lower setting sleeve by a set of transfer lugs which only lock the two together when the valve is pressured open. This is accomplished by a receiving groove on the core located so that when the core is in its uppermost position (no control line pres-sure), the lugs are free to move inward and DO NOT lock the top sub to the lower setting sleeve. When the core moves down (valve pressured open), this receiving groove moves down from the lugs, locking them out. With this mechanism, the running tool does not attempt to expand or lock out the locking keys unless there is sufficient control line pres-sure on the safety valve.

Once the lock and valve are driven into the landing nipple and sufficient control line pres-sure is applied, upward jarring through the top sub and the lower setting sleeve moves the locking sleeve of the lock mandrel upward against a locking shoulder on the lock ring. At this point the locking keys are in the expanded position. The locking keys are expanded to hold the lock and the valve in the landing nipple so that continued upward jarring will lock the locking sleeve in the up position. As the locking shoulder on the locking sleeve passes a similar shoulder on the ID of the lock ring, the locking lugs on the running tool move into a receiving groove on the core, releasing the lower setting sleeve. Simultaneously a receiving groove in the lower setting sleeve allows the retainer dogs to retract. At this point all engagements are retracted and the running tool releases from the lock and the safety valve.

Retrieval of the lock and the safety valve requires the use of an unlocking tool between the pulling tool and the prong. The unlocking tool has spring-biased engaging lugs free to retract until encountering the face of the locking sleeve of the lock mandrel. Downward jarring overrides the lock ring, allowing downward relative movement to the locking sleeve of the lock mandrel. The unlocking tool is designed so as to not allow the pulling tool to engage the lock mandrel fish neck until the locking sleeve is unlocked. An upward shearing pulling tool (GR) is required for proper operation. Should a conventional down shear pulling tool (GS) be used, the unlocking tool will not allow the pulling tool to move down far enough to shear on the skirt. For this reason, a GR is recommended.

3.0 ProcedureInstallation Procedure1. Place the safety valve assembly into a vise and attach any fittings necessary to

operate it with a hand pump or other hydraulic pump.

2. Remove the adjustable core extension from the running tool. Back the socket-head cap screw out with a hex wrench just until the core extension can be removed. It is not necessary to completely remove the screw. Loosen the jam nuts. With the safety valve pressured open (refer to the Operating Procedures for the valve for the correct opening pressures), insert the core extension into the up end bore of the valve. Adjust the all-thread so that the upper end is flush with the very top of the safety valve housing. This adjustment maxi-mizes bypass flow.

Adjustments with the all-thread below flush will provide less bypass while adjustments above flush will not allow the running tool to release. This adjustment must be done with the safety valve pressured fully open. Return the jam nuts against the bearing disk and tighten. Check the adjustment after the jam nuts are tightened to insure the adjustment is correct.

Remember "Flush or below, all set to go.” Reinstall the core extension on the running tool. Tighten the cap screw. The extension should be free to rotate but retained by the screw.

Note The adjustable extension replaces what would be considered a running prong with conventional safety valve lock systems and provides essentially the same function. The adjustability allows the running tool to accommodate many safety valves, Halliburton and others, without having to obtain special running prongs. The core extension OD and the adjustment range is listed on the Design Specification Data for the running tool.

Core Extension Adjustment

3. Make up the lock mandrel to the safety valve. The lock mandrel may be either locked or unlocked.

4. Prepare the running tool for insertion. Stand the running tool on the top sub, inverted with the core extension up. Push the core down, then pull it up. The lower setting sleeve should drop freely, and the retaining dogs and the locking lugs should be free to retract.

5. Pump the valve open with a hand pump or other surface pump. Visually check to insure the valve is open completely. Refer to the Operating Proce-dures for the valve for the correct opening pressures.

6. Insert the running tool as positioned in Step 4 with all the engagements retracted. Push the running tool into the lock until the retaining dogs are

inside the fish neck and the top sub contacts the top of the lock mandrel fish neck.

Note If the running tool is installed into a locked lock mandrel, it will be neces-sary to insert the running tool into the lock until the retaining dogs are inside the fish neck; attach a set of jars and 3 ft. of stem to jar towards the lock, unlocking the lock mandrel, and be ready to continue to Step 7.

7. With the running tool installed, hold the top sub down in contact with the lock mandrel fish neck. Release the hydraulic pressure on the safety valve. The lock mandrel keys may try to expand as the valve closes against the running tool. This is normal. Pull the top sub of the running tool away from the lock mandrel to its full extension and push it back against the lock mandrel fish neck. The keys should retract and the top sub should now travel freely from the extended position to the fish neck without expanding the keys. The top sub is lightly spring-loaded to the extended position and may or may not extend on its own in the horizontal position. It does not extend on its own in a vertical position.

Top Sub Against Fishneck

Top Sub Extended Running Tool Installation

Once the proper installation is assured remove all the fittings from the safety valve. The running tool/lock/valve assembly is now ready to be attached to the tool string.

8. Run down hole to the SV landing nipple. Jar down until the valve is against the no-go. Set the toolstring weight on the lock and valve.

9. Pressure up the control line to the proper pressure, opening the valve.

10. Once control line pressure is established, jar down once or twice to insure con-tact with the no-go. Jar up until the running tool has released. Pull out of the hole.

Note If for some reason the valve does not open when the control line pressure is applied, the upward jarring will not set the lock and valve, but extract it from the landing nipple. A check of the weight indicator will verify a release.

11. Visually inspect the running tool for damage of any sort. If there should be any dam-age to the running tool, it would be unsafe to assume the valve is properly set and should be pulled and reset.

12. The valve is now set and locked into place.

Retrieving1. Attach the specified unlocking tool and pulling prong to the appropriate GR-

type pulling tool. Once assembled, check the unlocking tool to ensure the unlocking lugs are free to move inward (retracted). The assembly is now ready to attach to the tool string.

Note Should it be necessary to run a ball closure type safety valve with a con-ventional (brass sub type) pulling prong, the length of the prong extension will need to be shortened and rethreaded by an amount listed as make-up length in the Design Specification Data for the unlocking tool. The thread size and depth are also listed in the Design Specification Data to provide for this modification.

2. Ensure by whatever means available that the valve is equalized. Control line pressure alone will not assure the valve is open and equalized. The pulling prong may have to be omitted to pull an equalized SV with an inoperative ball closure.

CAUTION Without a pulling prong there is no mechanical safeguard against the possibility of pulling a safety valve that has not equalized.

3. Jar down two to five times or until the pulling tool latches the lock fish neck, this is verified by a bind on the line. The pulling tool will only latch the fish neck when the lock mandrel is unlocked.

4. Once the pulling tool has latched, the valve can be pulled by upward jar action. Since the GR is a shear up tool, a persistent application of small or moderate jar strokes followed by bind on the line occasionally. Monitor the tool weight to indicate if the valve has been retrieved. Pull out of the hole.

Note If the GR-type pulling tool continuously shears off due to an extremely tight valve, a GS-type pulling tool can be used only if the unlocking tool is not used. Keep in mind that once the GR tool with the unlocking tool has latched the lock mandrel, it will be unlocked. If the GR shears off, the lock mandrel/valve is not relocked.

CAUTION DO NOT attempt to pull the valve using a GS with the unlocking tool attached. The unlocking tool would not permit the GS to shear off.

Slickline Operations Manual SL 2.16: FBN Lock System

SL 2.16: FBN Lock System

1.0 ScopeThe Halliburton FBN Lock Mandrel & Nipple system is designed to provide a means by which an indefinite number of identical landing nipples can be installed in a given tubing string. The FBN lock mandrel can be selectively set in any one of its associated landing nipples, and when locked in place, will withstand a differ-ential pressure from either direction.

2.0 General InformationThe Halliburton FBN Lock Mandrel is a mechanically operated lock that can be selectively located and set by a Halliburton FBN Running Tool. The running tool, when attached to a lock mandrel and placed in the selective position, holds the key and element expander sleeve in the fully extended position. With the expander sleeve in the fully extended position, the key springs act as cantilevers to bias the keys in to the retracted position.

With the keys retracted, the lock mandrel can be lowered through a series of iden-tical landing nipples without locating. However, when the lock mandrel is moved up through any one of the nipples, the locating dogs on the running tool locate the lower end of the nipple hone bore. Further upward movement through the nip-ple results in the running tool moving the expander sleeve down into the control position. As the expander sleeve moves from the selective position to the control position, the lower end moves under the offset bend in the key springs, causing the key springs and keys to be biased outward toward their expanded position. At this stage the expander sleeve has not moved under the keys; therefore, the keys can flex from the expanded to the retracted position when being pulled upward through a nipple or series of nipples. Likewise, the expander sleeve has not, at this point, moved under the element.

The shoulders on the keys and in the landing nipples are chamfered to prevent the spring bias keys from hanging in the profile when the lock mandrel is being pulled up through the nipple. However, when the lock mandrel is lowered back down into the nipple, the 90o shoulder on the keys engage the 90o shoulder in the landing nipple, thus landing the lock mandrel within the landing nipple.

Once the lock mandrel has been landed, downward jarring will shear the top shear pin in the running tool, which allows the expander sleeve to move down behind the keys concurrent with moving down behind the element.

Once the setting sequence has been completed, an overpull on the toolstring will determine that the mandrel is locked. Then upward jarring will shear the lower running tool shear pin permitting the running tool to be released from the lock mandrel and retrieved to the surface.

3.0 Procedure

RunningAttach the lock mandrel to the running tool as prescribed in the running tool’s Basic Design and Maintenance Instructions.

• The locator dogs of the running tool should be fully expanded.• The keys of the lock mandrel should be fully retracted.

• The shear pins should be center-punched and cross-punched to ensure that they stay in place during the running operation.

• Shear pins should be filed flush with the outside diameter of the running tool and lock mandrel.

1. Make up the running tool, lock mandrel, and desired subsurface flow controls to a standard wireline toolstring.

2. Lower the tool string into the tubing until the desired nipple is located.

3. Let the tool string pass through the nipple and stop. Raise the tools slowly until the weight indicator shows that the toolstring has stopped. This indi-cates that the locating dogs on the running tool are in position against the lower end of the nipple. An upward pull is required to trip the locating dogs, placing the running tool in a control position.

4. Lower the tool into the nipple. The expanded locking keys engage in the land-ing nipple recess to stop and set the lock mandrel.

5. Downward jar action will shear the upper shear pin in the running tool and move the expander sleeve of the lock mandrel under the keys and the ele-ment.

6. Test the lock mandrel by applying an upward strain on the wireline. If the mandrel is properly locked in the nipple, upward jarring shears the lower pin in the running tool and allows the toolstring to be returned to the surface.

If the mandrel is not properly locked in the nipple, it should jar loose before the lower pin is sheared. If this should happen, lower the mandrel back into the nip-ple and repeat Step 5.

Pulling

Note The proper pulling prong should always be used with the pulling tool, and adequate time for equalization should always be allowed before jarring upward on the lock mandrel.

1. Make up the proper size prong into the bottom of the pulling tool and attach the pulling tool to a standard wireline toolstring.

3. As the pulling tool enters the lock mandrel, the prong ensures that the flow control device is placed in the equalizing position. (Slight downward jar action may be necessary to shift the equalizing valve open.)

4. The weight of the toolstring should be allowed to rest on the lock mandrel while pressure across the subsurface flow control device is being equalized.

5. After equalization has been confirmed, an upward strain on the wireline indi-cates whether or not the pulling tool is latched into the fishneck of the lock mandrel.

7. Jar upward to move the expander sleeve up, allowing the keys and element to retract. Extract the lock mandrel from the landing nipple.

8. If the pin in the GR pulling tool shears without pulling the lock mandrel, then a Halliburton GS Pulling Tool can be used.

CAUTION Do not make up a pulling prong into the GS Pulling Tool when retrieving a lock mandrel with the equalizing valve attached. Any attempt to jar down and shear off will be obstructed by the pulling prong and cause damage to the pulling prong or equalizing valve.

Slickline Operations Manual SL 2.17: Monolock® System

SL 2.17: Monolock® System

1.0 ScopeThe Halliburton Monolock® Plug is a mechanically set plug used in nipple-less comple-tions. It can be set in a range of tubing weights at any depth and can hold pressure from above or below. It can be set below restrictions such as landing nipples and safety valves and can also be retrieved through the restrictions.

2.0 General InformationThe Monolock plug main components are the sealing element, the slips, the Belleville springs, the locking mechanisms, and an equalizing valve.

Note The figures shown in this document are for use as general information. There may be small variations between the different sizes of Monolocks.

Halliburton Monolock®

3.0 Procedure

RunningThis section refers to drawing 21MLxxxxx.

Note The drawing number 21MLxxxxx is used in this document to represent the drawing for the size of Monolock® plug being used.

The equalizing valve is run in the closed position and does not require a running prong. Since the plug does not pass through any sealing bores that require bypass, there is no need to have the equalizing valve open. The OD of the element is smaller than the Monolock OD, so the element cannot seal when passing through restrictions. Running with the equalizing valve in the closed position increases the plug’s reliability, because it becomes a static seal until it is opened during retrieval.

Once the desired location is reached, the DPU begins to set the plug. The pre-set-ting pins are sheared and relative downward movement of the housing causes both the element and upper wedge to move downward.

As the upper wedge and the lower wedge move closer together, the slips are forced outward. Resistance from the expanded slips causes the element and the Belleville springs to compress. After the slips and element make full contact with the tubing ID, the DPU continues to compress the Belleville springs until they are flat. This puts a compressive load of approximately 15,000 lbs. on the Belleville springs, the element, and the slips. The additional force required to shear the set-ting pins in the top sub is absorbed by the element and the slips. The setting pins each shear at 4,970 lbs. and up to 6 pins can be used, giving a maximum force of 29,820 lbs.

After the setting pins are sheared, the plug is fully set and the DPU can be retrieved. The Belleville springs provide approximately 15,000 lbs. of compressive energy on the element and the slips to help maintain a secure position. The com-pression on the element and the slips is maintained by the body lock ring, which has internal and external teeth that essentially lock the housing to the upper man-drel.

The following refers to drawings 21MLxxxxx, 146MLR00000, and 146DPU20.

Note Refer to BDMI No. 146DPU20 for details regarding the Downhole Power Unit (DPU).

1. Place the DPU in a vise, gripping on the thick-walled section of the motor housing. This area is located slightly above the motor housing’s identification groove.

2. Loosen the set screw on the DPU’s rod cap and remove the rod cap from the DPU, if so equipped.

3. Install the adapter kit’s shear sub on the DPU’s power rod.

4. Tighten the 4 set screws in the shear sub.5. Loosen the DPU’s drive housing 1/4 turn.

Note The drive housing has left-hand threads.

6. Using the shear sub as a knob, rotate the DPU’s power rod counter-clockwise to partially extend the power rod. The correct extension length varies, depending on the size of the Monolock®. Each shear sub is stamped with a stand-off distance, which is used to space it out correctly. The stand-off dis-tance is the distance from the back of the shear sub to the front of the DPU’s cap.

7. Tighten the DPU’s drive housing (left-hand thread).

8. Install the setting sleeve on the drive housing with the holes in the setting sleeve in-line with the holes in the shear sub.

9. Slide the Monolock’s top sub over the shear sub and pin together. Ensure that the shear pins are installed flush with the OD of the top sub.

10. Rotate the setting sleeve to cover the shear pins, then tighten the 2 set screws on the setting sleeve.

11. Ensure that there is a small gap (approximately 1/8-in.) between the adapter kit’s setting sleeve and the Monolock’s housing. Adjust if necessary.

12. Prepare the DPU per BDMI 146DPU20.

13. Run the Monolock® to the desired depth and note the hanging weight. No manipula-tion of the tool is necessary.

14. Look for a small increase on the weight indicator as the DPU begins to set the Mono-lock.

15. As soon as the setting pins shear, the hanging weight will drop to that of the DPU and running hardware. The Monolock will be fully set at this point.

Note If the Monolock does not fully set (the setting pins do not shear), jar up to mechanically shear the setting pins. This action will not fully set the Monolock because the mechanical shearing of the setting pins merely releases the DPU and running hardware from the Monolock. The improperly set Monolock must be retrieved.

16. Retrieve the DPU and running hardware.

Note Refer to the “Running” section of this document for more information.

PullingThis section refers to drawings 21MLxxxxx and 146MLP00000.

The plug is retrieved with the DPU and the pulling prong assembly. When the DPU reaches the set plug, the end of the prong mechanically pushes the valve spool off-seat. Some light downward jarring may be required. This action opens the equalizing ports in the equalizing valve housing and allows any pressure dif-ferential to equalize.

CAUTION Do not attempt to pull the Monolock while attached to a down-to-shear pulling tool. The downward jarring could release the pulling tool from the DPU and Monolock. Since the DPU has a self-contained power source, it would still be able to unset the Monolock and both tools would drop downhole.

During the equalizing process, the DPU is not running and can be pulled out of the plug to allow uninhibited equalization. This is possible because the pulling collet is unsupported and can collapse into the prong’s groove to enter and exit the releasing sleeve fishneck. An overpull of 300-400 lbs is required to pull the col-let out of the releasing sleeve fishneck.

Note The 300-400 lb overpull should be used to verify that the collet has entered the fishneck.

Once the equalization process is complete, the DPU is set back down on the top sub. Light downward jarring ensures that the collet is re-engaged in the releasing sleeve fishneck. When the DPU starts running, the prong will extend to push the equalizing valve down. Due to seal friction at the equalizing valve, the relative motion between the DPU and prong will actually lift the DPU and prong upward (away from the Monolock’s® top sub). This also causes the collet to move upward and away from the groove on the prong. By the time the upper angle of the collet reaches the shoulder on the fishneck, it will be fully supported by the prong. This locks the collet in the fishneck. The prong is then forced to stroke down and push the equalizing valve against the shoulder in the equalizing valve housing.

The shear pins between the releasing sleeve and the upper mandrel are then sheared as the releasing sleeve is pulled upward.

The shearing releases the threaded collet of the lower mandrel from the upper mandrel. As the lower mandrel collet releases, the energy stored in the element, slips, and Belleville springs is released. This action unsets the plug.

The DPU continues to push the prong downward, essentially stretching the plug. This involves relative pulling through the equalizing valve housing, the lower mandrel, the lower wedge, the slips, the upper wedge, the element, and the hous-ing. Since the element may have taken a set, this stretching action helps reduce the element’s diameter to allow easier retrieval or passage through any restrictions. Downward travel of all the mentioned items continues until the pick-up ring

snaps into the groove of the upper mandrel. The square shoulder in the upper mandrel groove stops the downward travel of the pick-up ring, the thrust ring, the spiral ring, and the housing.

Since the upper end of the element is restrained by the housing, the continued downward travel of the prong results in elongation of the element. The elongation continues until the element is stretched to its original length and OD. The DPU then goes into idle mode and linear motion stops. During the DPU’s idle time, the prong begins to rotate. This rotation continues until the DPU times out. To pre-vent any damage to the upper end of the valve spool due to relative rotation and to reduce the effects of the DPU’s left-handed rotation, the prong has a free-spin-ning equalizing tip. This tip allows relative rotation to occur within the prong assembly. The shear ring is pinned to the prong, keeping the tip in place. This allows the tip to shear the pins in the shear ring in the unlikely event that full downward travel cannot be achieved. By shearing the tip, the collet remains posi-tively engaged and supported in the releasing sleeve fishneck and the plug can still be safely retrieved.

The plug can also be retrieved with a GS pulling tool. After latching the pulling tool in the releasing sleeve fishneck, upward jarring shears the shear pins between the releasing sleeve and the upper mandrel, moving the releasing sleeve up-ward. This allows the threaded collet of the lower mandrel to release from the upper

mandrel. As the lower mandrel collet releases, the energy stored in the element, slips, and Belleville springs is released. This action unsets the plug and allows it to be retrieved. This procedure does not allow for equalizing any pressure differen-tial. Because no stretching action occurs on the element, any set it developed will not be reduced. This could result in difficulty when passing through any restric-tion.

Note The GS pulling tool is not generally recommended and should only be used to retrieve plugs that have been in service for only a short time and under relatively low differential pressure.

Refer to drawings 21MLxxxxx, 146MLP00000, and 146DPU20.

1. Place the DPU in a vise, gripping on the thick-walled section of the motor housing. This area is located slightly above the motor housing’s identification groove.

2. Loosen the set screw on the DPU’s rod cap and remove the rod cap from the DPU, if so equipped.

3. Loosen the DPU’s drive housing 1/4 turn.

Note The drive housing has left-hand threads.

4. Rotate the DPU’s power rod counter-clockwise to partially extend it. The power rod should only be extended far enough to allow access to the four set screws in the prong through the holes in the collet.

Note Do not fully extend the power rod. The DPU’s guide keys will need to be re-engaged in their slots if the power rod is fully extended. This will require com-pletely removing the DPU’s drive housing.

5. Remove the prong housing from the pulling prong assembly.

6. Slide the remainder of the prong assembly over the partially extended power rod.

7. Thread the prong onto the DPU’s power rod and tighten. This requires tight-ening the DPU’s drive housing to prevent the power rod from rotating.

8. Tighten the four set screws on the prong. The set screws can be tightened through the holes in the collet.

Note The figure shown is for a 4 1/2-in. prong assembly. The larger prong assemblies do not have a threaded shear nut or set screw attached to the collet. The collet is pinned directly to the shear sleeve on the larger assemblies.

9. Reinstall the prong housing over the entire prong assembly and tighten on the drive housing.

10. Tighten the 2 set screws on the prong housing.

11. Retract the power rod clockwise until the prong stops on the 45° shoulder in the collet (or shear nut). This requires loosening the DPU's drive housing. At this point the ends of the collet can collapse into the groove on the prong.

Note The collet must be able to collapse in order to engage the Monolock's® releasing sleeve fishneck.

12. Tighten the drive housing to lock the power rod in position.

13. Verify that the collet still collapses into the groove on the prong. Adjust if nec-essary.

14. Prepare the DPU per BDMI 146DPU20.

15. Run the DPU and pulling prong to the set Monolock.16. When the DPU and pulling prong reach the set Monolock, there will be a drop

in hanging weight.17. Jar down to mechanically push the equalizing valve down.

Note At this point the DPU is not running. Ensure that the DPU does not remain still long enough for the motor to start. Once the DPU starts running, it will be impossible for the collet to enter the fishneck. It will then be necessary to retrieve the DPU and pulling prong without unsetting the Monolock.

CAUTION Do not attempt to pull the Monolock® while attached to a down-to-shear pulling tool. The downward jarring could release the pulling tool from the DPU and Monolock. Since the DPU has a self-contained power source, it would still be able to unset the Monolock and both tools would drop downhole.

18. Once the equalization process is complete, drop the DPU and pulling prong back into the Monolock.

19. Pull up slowly to verify that the collet is engaged in the releasing sleeve fish-neck. An overpull of 300-400 lbs is required to temporarily pull the collet out of the fishneck.

20. Drop the DPU and pulling prong back into the fishneck.21. Pull up slowly to re-verify that the collet is re-engaged in the fishneck, but do

not overpull.22. Slack off on the wireline to release all wireline tension.

Note The pulling prong assembly must be fully seated on the Monolock’s top sub when the DPU starts.

23. Allow the DPU to start running.

24. There will be a sudden jump in hanging weight as soon as the Monolock unsets.

25. Allow the DPU to reach its full stroke before attempting to retrieve through any restrictions.

Note If the Monolock has been in service for a long period of time under high pressure and temperature, it may be necessary to jar down on the Monolock to help the element release from the tubing ID.

26. Approach restrictions slowly. The element may have taken a set during ser-vice and may be difficult to drift through the restriction. Although the pulling prong stretches the element to its original length during the DPU’s stroke, some light jarring may be required to squeeze the element through the restric-tion.

Note If there is a problem in pulling the Monolock, the DPU and pulling prong assembly may be released from the Monolock by jarring up. Upward jarring shears the emergency release pins in the pulling prong assembly. This allows the DPU and pulling prong assembly to be retrieved.

27. Once the DPU/Monolock® assembly has been removed from the well, place the assembly in a vice, gripping on the DPU motor housing above the identifi-cation groove. Support the Monolock with a hoist or jack stand.

28. Loosen the set screws in the prong housing until the thread is completely dis-engaged.

29. Pull the Monolock away from the DPU. Use steady movement to reduce the force required to collapse collets.

Note Pulling the Monolock will cause the collets of the pulling prong to be posi-tioned in the groove of the prong. This frees the collets to unlatch from the Mono-lock’s releasing sleeve fishneck.

Note The plug can also be retrieved with a GS pulling tool. After latching the pulling tool in the releasing sleeve fishneck, upward jarring will unset the Mono-lock. This procedure does not allow for equalizing any pressure differential and does not stretch the element after it is unset.

The GS pulling tool is not generally recommended and should only be used to retrieve plugs that have been in service for only a short time and under relatively low differential pressure.

Note Refer to the “Pulling” section of this document for more information.

Slickline Operations Manual SL 2.18: Subsurface Safety Valve Considerations

SL 2.18: Subsurface Safety Valve Considerations

1.0 ScopeSubsurface safety valves are placed in the well bore to prevent the well from flow-ing uncontrolled in the event that the integrity of the well’s surface pressure con-taining equipment is lost. Safety valves protect lives, environments, property, and formations.

2.0 General InformationBecause of the reasons listed above, many times local, state, and federal govern-ment regulations may require the installation of safety valves in the well. These regulations may include requirements about what type of safety valve system must be used and standards for installation and testing of the safety valves. Addi-tionally, many times the production company itself will have policies which require the use of safety valves. Whatever the reason for installing the safety valve, the following text covers several different designs of subsurface controlled subsurface safety valves which are in common use in today’s industry.

3.0 Procedure

Direct Controlled Subsurface Safety Valves (SSCSV)

Note Closure flow rates should be as large as possible within the limits of the applicable rules and regulations governing an operating area but should be smaller than the maximum capability of the well. The closure flow rate should be greater than the well test rate.

The bean diameter should not exceed 80 percent of the flow tube diameter. The diameter of the bean assembly in a safety valve should be the same as used in siz-ing the safety valve.

The pressure drop through the bean should be within the range specified for each valve.

Normally, the pressure drop through the bean should not exceed 15 percent of the valve of the pressure immediately under the safety valve in gas wells.

Differential Operated (Types MO-JO, velocity-type)

Note A running prong is not necessary when running the velocity-type valve.

Never run a velocity safety valve without an equalizing valve between the safety valve and lock mandrel.

Slickline Operations Manual SL 2.18: Subsurface Safety Valve Considerations

Ambient Operated (Types H & K, velocity-type)

Note H and K safety valves are pressurized containers and should be treated with more care than if they were empty.

Never run an ambient safety valve without an equalizing between the safety valve and lock mandrel.

Injection Safety Valves (T, MC, & JC)• See attached papers on subsurface safety valve systems.

Indirect-controlled subsurface safety valve (SCSSV)• See attached papers on SCSSV.

Slickline Operations Manual SL 2.19: Running and Pulling Gas Lift Valves

SL 2.19: Running and Pulling Gas Lift Valves

1.0 ScopeMany wells are produced using gas lift to lighten the fluid column. Slickline is often used to service (run and pull) gas lift valves from these wells.

2.0 General InformationThere are two different types of gas lift systems: continuous and intermittent. Continuous-lift type systems inject gas continuously into the fluid column. With intermittent gas lift the fluid column in the tubing is allowed to rise before gas in injected into the well.

Gas lift valves (GLVs) can be placed in side pocket mandrels, outside of well flow, or in concentric fashion. Concentric-type GLVs will block the ID or through the tubing.

GLVs have a check valve to stop tubing pressure from flowing into the annulus between the tubing.

A kick-over tool (KOT) is required to run and pull gas lift valves from side pocket mandrels.

Some gas lift mandrels contain orienting sleeves or guides and some are non-ori-enting. The orienting-type side pocket mandrel has a key slot built into it that aligns the KOT with the gas lift valve pocket to ease in setting and pulling. It is primarily used in deviated wells.

Often flowing wells are completed with side pocket mandrels loaded with dummy gas lift valves. These are later replaced with live gas lift valve when the well stops flowing on its own.

3.0 Procedure1. Gauge run should be made prior to beginning job.

2. If you are not pulling dummies, set a stop to catch any dropped valves.

Note Junk basket with internal fishing neck may be set on top of stop to catch valves or make them easier to fish.

3. Equalize the tubing and casing and pull the bottom valve first. Circulate heavy fluid out of the annulus and tubing, and continue pulling valve or dummies from bottom up.

Note TSG-CSG equalization should be based on BHP, not surface pressure.

Note Use a T type standing valve as opposed to a dart-type test tool, as it is eas-ier to pull with a fluid load on top.

Slickline Operations Manual SL 2.19: Running and Pulling Gas Lift Valves

4. Run a new string of valves or dummies from the top down.

5. Start injection to pressure up on the casing and open the well prior to pulling the circulation device or plug to make sure the valves are in the pockets.

Note Do not run 2 arm L-type KOT when running GLV’s into side pockets man-drels with positioning sleeves. The arms may hang up in the positioning sleeves key slot.

6. Pressure up on tubing after bleeding easily it ensure that the check valves hold.

Note Even though casing shows zero pressure there may be a hydrostatic pres-sure differential at the valve depth. Calculate the pressure inside and outside the tubing to determine the pressure.

7. Pull the circulating device, plug, stop and junk basket depending on what you have in the well.

8. Return the well to production.

CAUTION Do not use quick connects on the bottom of the KOT as this will not allow the tool to kick over.

Slickline Operations Manual SL 2.20: Running and Pulling Packoffs

SL 2.20: Running and Pulling Packoffs

1.0 ScopePackoff equipment is used to packoff holes in tubing. Also, it is used to run con-centric gas lift packoffs.

2.0 General InformationWhen using packoff equipment straddle and packoff holes or other communica-tion avenues in the tubing string.

3.0 Procedure1. Make a gauge run before beginning the job.

2. Run in hole and set the anchor (collar stop, slip stop) approximately 3 feet below the hole.

3. Run in hole packoff assembly on a GS to the desired depth. Shear off the pack-off and come out of the hole with GS.

4. Run in hole with a blind box, jar down and set the packoff.

5. Run in and set the hold down slip (G packoff anchor).

Note Pin the top packoff prior to running. This ensures that the bottom packoff element sets first.

6. When pulling, use a GS pulling tool for an internal fishing neck on packoff equipment.

7. Use an RS pulling tool for external fishing necks.

Slickline Operations Manual SL 2.21: Opening and Closing Sliding Sleeves

SL 2.21: Opening and Closing Sliding Sleeves

1.0 ScopeA means to achieve communication between the tubing and casing.

2.0 General Information• Can be used to displace fluid from backside.

• Can be used to produce alternate zones.• Other circulating devices are ported nipple, gas lift mandrels, etc.

• Must be aware of possible differential pressure when shifting the sleeve.• A sleeve must be shifted with positive shear type (non-self releasing) keys

when there is another SP which generates in the same directions as the one you wish to manipulate or when it is above the one you wish to manipulate. The positive tool is designed to only release when the pin is sheared, thus allowing the tool to be withdrawn from the wellbore without affecting any other sleeves.

• The standard 42BO positioning tool with self-releasing keys is used when there is one sleeve in the well or you want to shift the top sleeve.

• The selective position tool is designed for downward shifting only using self-releasing keys. The tool is made selective by the lower section. It resembles the X-line running tool.

3.0 Procedure1. A gauge run should be made prior to starting the job.

2. Determine the proper positioning tool to be used in shifting the subject sleeve, and make up on the tool string.

3. Equalize the pressure difference across the sleeve prior to shifting the sleeve open.

4. Run in hole to sleeve and locate profile, shift sleeve in the direction desired. Monitor tubing and casing pressure for changes to give you an indication it has shifted.

5. Pressure up on the tubing to see if you have communication to verify that the sleeve is open or closed.

Note As soon as an indication of increasing or decreasing pressure on the tubing or casing is noted, stop jarring until the pressure equalizes.

Once you think it is open or closed, make a few passes through the sleeve to dou-ble check.

BHP, Spinner Survey, and Temperature Surveys can also be run to determine if the sleeve is open.

Slickline Operations Manual SL 2.22: Use of Test Tools

SL 2.22: Use of Test Tools

1.0 ScopeTest tools are used to pressure the tubing string.

2.0 General InformationTest tools hold pressure only from above. The tools are self-equalizing and are no/selective set.

3.0 Procedure1. Make a gauge run before beginning the job.2. Attach to a running tool and run in hole to the desired depth (nipple) and set

in the nipple.3. Pressure up and test the tubing.

4. Run in hole with an RB pulling tool, jar down to latch, and remove the test tool from well.

Slickline Operations Manual SL 2.23: Bailing Operations

SL 2.23: Bailing Operations

1.0 ScopeA bailer can be used to remove sand and other particular debris and materials from a wellbore. This material may have bridged over or built up alongside the tubing wall.

2.0 General InformationThere are different types of bailers: the pump bailer, the drive down bailer, and the hydrostatic bailer.

• Pump Bailer - The pump bailer has a cylinder-shaped barrel, where a rod is used on a piston assembly. This piston assembly sucks material into the barrel. This material is trapped inside by a check valve (which is either a ball or flap-per). This check valve is called a “bailer bottom.” (see cautions).

• Drive Down Bailer - This bailer also has a cylinder-shaped barrel, but it differs from the pump bailer. This bailer has tip sub made up on top going a 5/8 in. sucker rod thread. On the bottom of the bailer you have a check valve, or bailer bottom, as it is known. This bailer uses the hammering action of the wireline tool string to drive it into the material that is being bailed (see cau-tions).

• Hydrostatic Bailer - This is cylinder-shaped, consisting of a seal chamber that contains air at atmospheric pressure. The seal at the lower end of the barrel is a brass shear disc. A skirt and ball-type check valve is made up on the lower end of the barrel, below the shear disc. The skirt on the bailer bottom is designed with a larger I.D., which allows it to move down and around with the fishing neck of the subsurface control device. When the skirt stops on the downhole control device, a few downward jarring strokes will shear the brass disc. When this occurs, the sudden influx of well fluid or gas into the chamber will carry the remaining debris past the check valve and into the chamber.

Note Special junk baskets are designed to catch larger parts that cannot get around check valve. Also, a hydrostatic bailer should only be used for cleaning off a minor amount of debris above a fish neck or other hard component. Do not run in to bail soft material, since the bailer will suck itself into the material and may become stuck.

3.0 Procedure1. A proper gauge run should be made.

2. Attach to a tool string and zero at the tubing hanger.3. Run in hole at moderate speed (taking consideration of nipples, tight spots,

gas lift mandrels, collars). Once you reach the obstruction, sit down, then pick up on the tool string, slowly lifting the rod on the piston assembly. As this is done debris material is sucked into barrel. This procedure is done over and over until the operator sees that he is no longer making hole, or feels the bailer is full.

4. Remove the bailer from well. (Repeat as above. Clean up debris, sand, etc. as necessary).

CAUTION If the bridge that is being bailed has a pressure differential below it, the tubing above the bridge should be completely filled with a fluid and/or be pressurized to a pressure that is at least equal to the pressure below the bridge. This is to pre-vent the wireline tool string from being blown up the hole when the bailer breaks through or weakens the bridge.

After each upward pump stroke, the bailer should be pulled up the hole a few feet above the original depth of the top of the bridge. This will help to avoid the possi-bility of the bailer becoming stuck in the bridge.

Note A muleshoe bailer bottom seems to work best when bailing sand.

A flat-bottom bailer with noted chisel marks helps to give the operator indications when fishing on tools, wire, etc.

Also, while bailing, the bailer will sometimes get stuck. When this happens, pull a couple of hundred pounds over pickup weight and stop. Have patience and wait. This will normally be enough to pull free.

During bailing operations, it is recommended to pickup out of debris to ensure that debris is not falling back on top of tools, causing the tool string to become stuck and/or lose jarring action.

Care should be used when breaking the bailer down because it is possible for sand to bridge over inside the bailer, causing a pressure differential.

CAUTION The hydrostatic bailer should not be used until the sand has been removed from the tubing down to the top of the subsurface control device. When jarring down on a long sand bridge to shear the disc in the hydrostatic bailer, the bailer may be driven into the bridge and become stuck even if the disc does not shear. If the disc shears, the bailer may bury itself in the bridge to the extent that it may become stuck.

After retrieving the hydrostatic bailer to the surface, care must be taken when opening the bailer due to the possibility of pressure being trapped in the chamber. Even though the bailer is equipped with an automatic pressure relief valve and also a normal pressure relief valve, it is possible that the internal pressure port leading to both relief valves could become plugged. The upper allen head set screw should always be backed out at least two to three rounds to allow the ball relief valve to move off seat before opening the bailer.

Note Shear disc come in: (Hydrostatic pressure ratings) Thin 4025 psi, Medium 7450 psi, Thick 12, 175 psi. Also, snorkel bottoms for hydrostatic bailers made to get inside locks.

Slickline Operations Manual SL 2.24: General BHP/BHT Surveys

SL 2.24: General BHP/BHT Surveys

Slickline Operations Manual SL 2.25: Caliper Surveys

SL 2.25: Caliper Surveys

1.0 ScopeMeans of determining the integrity of tubular goods.

2.0 General InformationCaliper surveys are run to determine the erosion, corrosion, build up and defor-mity of tubular goods.

3.0 Procedure

1. Make proper gauge run to the target depth. POOH.2. Make caliper dummy run to the target depth. POOH.

3. Run in hole with caliper to the target depth. POOH is normally at 60 ft. per minute.

Note Calipers are run by Kinley-trained personnel.

For more information contact Kinley or Hornbeck.

Slickline Operations Manual SL 2.26: Perforating (Otis Type “A”) Mechanical

SL 2.26: Perforating (Otis Type “A”) Mechanical

1.0 ScopePerforating equipment is used to punch holes in tubing walls.

2.0 General InformationThe perforators may either be mechanical or explosive in nature. These include the Kinley Perforator and the Otis type ‘A’ perforator.

3.0 Procedure - Mechanical1. Make a gauge run.2. Properly assemble and pin the perforator.

3. Lower the perforator into the well and seat on stop at the desired depth.

Note A stop may be previously set downhole or it may be run on the bottom of the perforator.

4. Once seated, jar downward lightly to shear the two small pins.

5. Pull upward on the wireline to move the punch into contact with the tubing wall and at the same time move the upper, serrated end of the perforator housing into contact with the tubing wall.

6. Use light to moderate upward on wireline to move the punch into contact with the tubing wall and at the same time move the upper, serrated end of the perforator housing into contact with the tubing wall.

7. Continue upward jarring after the punch penetrates the tubing wall.

Note This allows the reverse taper on the double tapered wedge to engage the front side of the base of the punch. This retracts the punch back into the perfora-tor, locks it in the fully retracted position and frees the perforator to be retrieved.

8. Deactivate the perforator to the nonperforating position by jarring downward to shear the safety shear pin. This causes the tool to be locked in a nonperfo-rating position and allows it to be retrieved from the well without perforating the tubing.

Note When using this perforator to mechanically punch a hole in the tubing wall, the wireline operator should not use more than 30 to 35 lb of stem weight in the tool string unless high surface pressure in the well requires that he use more weight to get the tools into the well. Depending upon the amount of stem weight being used, only very little to moderate upward jarring action should be used to perforate the tubing. Excessive stem weight and/or severe upward jarring impacts are not necessary with this perforator and, in fact will be detrimental to its performance.

Slickline Operations Manual SL 2.26: Perforating (OTIS Type “A”) Mechanical

Otis® A Tubing Perforator

Slickline Operations Manual SL 2.27: Swabbing Operations

SL 2.27: Swabbing Operations

1.0 ScopeSwabbing is a means of lifting fluid from the wellbore via wireline methods. The objective of swabbing is to remove enough fluid from the tubing to reduce the hydrostatic head off the formation to allow the well to come in. Use of proper lighting is required to be aware of returns indicating that the well may be coming in.

2.0 General Information• Swabbing is done by means of cylindrical swab cups lowered in the well to a

desired depth and pulled back to surface quickly, expelling fluid above cups through a pump-in-sub or the flowline.

• Swabbing is usually done with 3 1/16 in. wire or 1.25 in. wire.• Swab cups have to be cut down for heavy wall tubing.

3.0 Procedure1. A gauge run should be made prior to starting job.

2. Make sure the well is static without pressure on it.3. Run in hole with the swab mandrel with swab cups on it to a desired depth.

Note Start out at about 250- 300 ft. and see how it feels.

4. Pull out of hole quickly and watch for fluid or gas to start flowing.

5. Watch well for 3-5 minutes to see if gas or fluids start to flow.6. Repeat Step 3 and watch for fluid rising, and indication that the well may be

coming in.7. Repeat Steps 3,4, etc.

8. Do this until the well starts to flow or Company Man shuts you down.

CAUTION Be sure not to pull over what your wire is good for.

Check your swab cups periodically for wear. Change if necessary.

It is not recommended to swab over half the tubing capacity.

Note When swabbing through a gas lift mandrel you will lose fluid. Running tandem swab mandrels may help improve returns.

Slickline Operations Manual SL 2.28: Using Kinley Power Jars

SL 2.28: Using Kinley Power Jars

1.0 ScopeThe kinley power jars are used to deliver downward explosive force.

2.0 General InformationKinley power jars can be run on various slickline units. They are used to knock stuck chokes loose, puncture hole into bull plugs, and also drive spears into tan-gled wire.

3.0 Procedure1. Make a gauge run into the well to check the path.

2. Run power jars on slickline unit into the well until the “fish” is contacted.3. Use downward jarring strokes to shear the two safety pins. This enables the

firing pin to strike the primer to fire the shell. The drive head delivers a quick, hard blow downward.

Note If the fish does not move, redress and re-run the power jars.

Note A heavy toolstring is necessary to prevent toolstring from moving upward.

Slickline Operations Manual SL 2.29: General Wireline Fishing Operations

SL 2.29: General Wireline Fishing Operations

1.0 ScopeAny operation requiring the removal of various objects or debris from the well-bore that can’t be removed using standard wireline procedures or tools.

2.0 General Information• Prior to starting a fishing operation, accurate information pertaining to the

fish should be obtained.

• The tool string being used to fish with should have its exact lengths and O.D.’s recorded.

• Determine differentials if the fish is a flow control device.

• Make sure you have sufficient lubricator to cover the amount of tools in-hole.• Make sure the wireline valve is in good operating condition. Run two valves if

possible.• Take your time. Try not to lose any more tools.

3.0 Procedure1. Determine the top of fish, either a with wire finder, impression block, or gauge

run.2. Run the appropriate tool to latch. Fish.

3. Always take into consideration any pre and cons of the operation at hand. (ex. What to do if you latch fish, etc.) Remember well conditions.

4. Always keep communication lines open for suggestions and ideas.

5. Keep the office informed about progress, or lack of.

General Fishing Guidelines1. Keep accurate records of the lengths and diameters on each component of the

tool string and tools run into the well.2. Ensure sufficient lubricator length to cover work tool string and the length of

tools to be recovered.

3. Use the wireline valve to contain well pressure instead of the gate valve.4. Carefully check the fishing tools and equipment (before running) to make sure

that they will latch, (and also release from) the downhole fish.5. Discuss the operation with several operators/supervisors to gain as many

ideas as possible.6. Prior to running a fishing tool, carefully consider the options and the possible

undesirable consequences of running that particular tool.7. Think of other tools that could be run if the first tool is not successful.

8. Carefully consider what action can be taken if a run does not result in the anticipated or desired outcome.

9. Attempt to remove broken wire first - then the tools.

10. A length of stem installed below the jars (when fishing wire) will help to pre-vent the jars from becoming fouled. Also consider the use of a substantial tubular jar rather than a link jar.

11. Measure and retain all wire fished from the well until the job is complete. This allows you to be aware of the amount of wire remaining in the well after each step of the fishing operation.

12. Use an impression block when necessary to check the downhole situation.

Tool Summary

Tool Use Comment

Bowen Wire Finder locates top of wire difficult to pass nipple I.D.

Bell Type WIre Finder locates top of wire difficult to pass nipple I.D.

Wire Scratcher locates top of wire use care around SPM’s

Wire Grab latches ball of wire do not jar deeply into nest of wire

Center Spear pierces thick ball of wire do not jar deeply into nest of wire

Tubular jars large I.D. tubing & when wire is in the hole

reduces hazard of fouling jars

Cutter Bar cuts broken wire at rope socket Calculate blind box size before use.

Go-Devil: Beveled cuts wire at rope socket. blunt beveled end. Do not drop in dry gas well. Check O.D.’s & I.D.’s

Go-Devil: Flat base to cut on, adds wt., cutting force for sneppers.

blunt beveled end. Do not drop in dry gas well. Check O.D.’s & I.D.’s

Kinley Snepper cuts wire close to the rope socket returns on line (cuts approx. 3in. above rope socket)

Upside Down Sneeper cuts wire close to the rope socket Does not return on line (cuts approx. 2ft. above socket)

Flopetrol Cutter cuts wire close to socket does not return on line

Side Wall Cutter cuts broken wire in tubing care required when running

Magnet recovers small pieces magnetic steel only

Overshot latches worn or smooth items run on rope socket & SB if not equipped w/shear pin

Broach increases I.D. insure dimensions before use

Impression Block obtains “picture” redress before use

Slickline Operations Manual SL 2.30: General ETD Operations

SL 2.30: General ETD Operations

1.0 ScopeThe electronic triggering devices are run on slickline, to fire various explosive tools as an alternative to costly electric line.

2.0 General InformationElectronic Triggering Devices are used for several well applications.

• perforate tubing

• set bridge plugs• set packers

• set patches• set cement retainers

• cut tubing or casing• dump bail cement or sand

• needs a licensed explosive specialist to make up the tools, the ETD man is in charge once his tools are on the tool string.

3.0 Procedure1. Make a gauge run to the desire depth.

2. The ETD man makes up his ETD tools onto the tool string.3. Run in hole to desired depth while the ETD tool is on slickline. The ETD spe-

cialist is in charge of running and pulling procedures.

Slickline Operations Manual SL 2.31: Running Long Assemblies With Pressure

SL 2.31: Running Long Assemblies With Pressure

1.0 ScopeRunning long sections of screen can be difficult, but with proper preparation, the job can be completed with little or no difficulty.

2.0 General Information• Long assemblies must be made up at the surface while lowering the assembly

into the well bore. To accomplish this, the well must be killed, or the TRSV can be shut in some instances to allow for space to lower the assembly into the well. This check valve is called a bailer bottom (see cautions).

• In some cases, a heavy pill such as K-Max can be used as a spacer/cushion in case the assembly is accidentally dropped. As you can see, safety precautions must be taken and the job carefully planned out.

• The assembly is usually set in the wellbore by means of a locking device to secure the screen and to pack it off. The screen must be packed off so the flow of the well will go through the screen, and not around it.

• The weight of the screen and fluid in the hole must be taken into account to determine the wireline size to be used.

• Good records must be taken on lengths and ODs for future reference such as in the possibility of retrieval.

3.0 Procedure1. A gauge run must be made. If possible, a dummy run should be made.2. Gather all tools and check all connections for good quality and fit.

3. After well is killed or TRSV is closed and secured, lower the first joint into the well and secure with clamps.

4. Continue adding additional sections until all are made up and hanging in the wellbore.

5. Make up the tool string and locking/hanging device on to the assembly. Enough lubricator must be used to cover the tool string and running tool when retrieved back to surface.

6. Lower the assembly into the wellbore at a slow speed to avoid any possibility of damaging the screen.

7. Set the assembly at the correct depth and POOH.

Slickline Operations Manual SL 2.32: Shifting (Knocking) Off TCP Guns

SL 2.32: Shifting (Knocking) Off TCP Guns

1.0 ScopeShifting off TCP guns is similar to shifting open a sliding sleeve. In some cases, the same tool is used to shift the gun that opens the sleeve.

2.0 General Information• Releasing guns by means of wireline is done with a shifting tool. During the

shifting operation differentials need not be considered.

• The guns are release when the collet moves off of the retaining feature.• The shifting tool and tool string are not in the way and will not be affected

during the operation.

3.0 Procedure1. Make the proper gauge run to target depth.

2. Run in hole with positioning/shifting tool to target depth.3. Shift the tool in the proper direction to release the guns.

4. The shifting tool should pass freely through the releasing profile once the guns are released.

For more information contact Kinley or Hornbeck.

Slickline Operations Manual SL 2.33: Use of Downhole Purge/Surge Valves

SL 2.33: Use of Downhole Purge/Surge Valves

1.0 ScopeValves used to purge or surge (clean out) perforations.

2.0 General Information• Slickline run.

• Sets in nipple.• Pressure ratings acceptable to lock.

3.0 Procedure1. Gauge run.

2. Run in hole and set the tool in the nipple.

Note Purge tool (pressure in formation), Surge tool (formation flow)

Slickline Operations Manual SL 2.34: Deviated Well Operations

SL 2.34: Deviated Well Operations

1.0 ScopeWireline operation in deviated wells are trial and error. The proper tool string operating in a particular well must be established.

2.0 General Information• Tool strings with knuckle joints and roller stem are used in highly deviated

• Sometime smaller O.D. tool strings are used to reduce drag.

3.0 Procedure1. Before running anything into the well, read past the wireline report and find

out deviation, elevation, wellbore fluid property, true vertical depth (TVD), and measured depth (MD), etc.

2. Hydrostatic pressure is calculated at true vertical depth.3. If a known tool string has been used before, use same.

4. Make pick up more often than in a straight well for excessive drag.5. Note in your report weights encountered and tool string configuration, etc.

Slickline Operations Manual SL 2.35 High Pressure/Temperature Operations

SL 2.35 High Pressure/Temperature Operations

1.0 ScopeConsideration for handling pressure and temperature conditions should be made at all times when working with slickline. Additional planning and special consid-eration should be made when handling high surface pressures of 10,000psi and above and for wellbore temperatures in excess of 265oF.

2.0 General InformationThere is more potential for encountering a hazardous situation when performing slickline services on wells with pressures approaching 10,000 psi and above.

While working on high pressure/temperature jobs, it is recommended that a supervisor accompany the job. High pressure is defined as pressure or equal to or greater than 10,000 lb. High temperature involves temperatures above 265oF.

It is recommended to keep 1,500-2,000 lb above wellhead pressure on the grease seal lines. Use fresh/clean “honey-oil.” Care must be taken in handling high pres-sure equipment. High pressure equipment is considerably heavy. Three people, at least, should be used for rig up.

High pressure work is dangerous and must be handled with experienced work-ers. Also, it is recommended that an experienced supervisor accompany the wire-line crew.

When testing the tree and lubricator upon rigging up, maintain pressure on the actuator if fusible plug is used. Best practices would be to use grease the injection stuffing box for 11,000+psi jobs.

3.0 Procedure1. High Pressure

a. Make sure all equipment is current, as for as pressure, magnetic flux, and stress-crack testing.

b. Pressure-test the wireline valve as an extra safety precaution before going out on a job. Also, visually inspect lubricators and flanges to be used.

c. Have on hand a redress kit for the wireline valve, lubricator, and stuffing box. Also, extra autoclave valves and flange gaskets are recommended.

d. Upon arriving on location, examine the wellhead/tree. Also, note the work-ing pressure on the tree. Next, determine if you have the proper equipment to handle the job.

e. Hold a safety meeting with all people involved in performing the job. This includes the operator, service assistants, company representative and covers all matters related to the job.

f. After meeting, flange up on the tree and be sure to install a new flange gas-ket.

g. Position the wireline/slickline unit in the safest location possible, preferably upwind of the well.

h. Change all o-rings in the lubricator and assemble the necessary lubricator sections.

i. Install two autoclave valves per lubricator valve port/hole. The second valve per hole acts as a backup.

j. The proper installation of the autoclave has the lower bleed hole on the auto-clave and valve nearest the lubricator.

k. Do not apply teflon tape to the autoclave valve threads. The threads are not designed to hold pressure.

l. During operations the outer autoclave valve is closed and used as a pres-sure-bleeding device. The inner autoclave serves as a safety backup and remains open at all times.

m. It is necessary to remove and place all glands and packing within the stuff-ing box.

n. The recommended packing stack from top to bottom includes, 91T136 (hard black), 2 soft 91M2467, 1 91T120 (red), 1 soft 91M2467 (soft), 1 91T120 (red), and as many soft black as necessary.

o. Installing a new lower blowout preventer within the stuffing box is neces-sary. Pack the void in the stuffing box with appropriate grease.

p. A hydraulic stuffing box is recommended in high-pressure conditions.

q. Check the bleed allen screw valve within the stuffing box. Make sure the valve is closed.

r. Screw in the adjustment nut on the stuffing box until tension is noticed, then back off a quarter turn.

Note For wells containing high CO2 concentrations, back the adjustment nut off one-half to one complete turn. CO2 tends to make the packing expand and tighten.

s. When running wire in the hole, apply a mixture of STP and oil to the wire.t. When rigging down do not leave the wireline valve on the wellhead over-

night. This may allow damage to occur to the elastomers in the wireline valve due to explosive decompression of gases trapped within.

u. Pressure test the lubricator stack to working and/or customer requirements with glycol, if applicable.

Note Do not use glycol where there are zinc or calcium products present. Glycol turns zinc into a salt deposit and calcium into a “peanut butter” type substance. If glycol is used, then it should be removed/drained from the tree.

v. Purge air out of the lubricator section by pressuring up to 1,000 lb and then bleeding off. This prevents spontaneous combustion of products within the lubricator.

Note This step necessary only on the first run into the wellbore.

w. Use a liquid chamber to inject corrosive inhibitor grease. This protects the wireline and increases stuffing box life.

x. Install the liquid chamber immediately below the stuffing box.y. When using exotic wire (mp35, stainless steel,.108,.125) or per customer

request, employ a grease seal with flow tubes. Three to five flow tube sec-tions may be run.

Note The maximum line speed should be 200 ft/min. into and out of the well-bore.

z. Inject grease sealant at a point one flow tube above the lubricator.

aa. Install a return line below the stuffing box to capture used grease. At this point the stuffing acts as a wiper section or pressure backup device.

ab. Standard braided line should not be used when pressures exceed 3,000-4,000 lb. Dia-form is recommended for pressure above 3,000-4,000 psi. Dia-form is easier to seal and is a stronger braided wire.

ac. Use more weight/stem bar if braided line is employed on high pressure wells. Lead, tungsten, or spent uranium stem is recommended to shorten the tool string.

ad. When using braided line employ a double ram to accommodate the larger OD.

Note If the seal is lost, it is necessary to close the double rams on your lines and pump grease between the rams when closing the wireline valve.

ae. Fresh water should never be used on high-pressure gas wells.2. High Temperature

af. Special packing and seals are needed when temperatures exceed 260oF.ag. Use riton teflon and peak packing when working with high temperature/

pressures.ah. Q-V o-rings can also be used.

Slickline Operations Manual SL 2.36: Downhole Power Unit Operations

SL 2.36: Downhole Power Unit Operations

1.0 ScopeA service tool which has the capacity to set wellbore devices without the use of explosives.

2.0 General InformationThe DPU has a gradual setting motion which allows the slips and seating ele-ments of packers and bridge plugs to expand and conform uniformly against the tubing/casing wall, thus decreasing the chance of a misrun.

The gradual setting motion also eliminates the high impact stresses that are imposed upon downhole devices when using an explosive charge setting tool.

The DPU uses and electric gear motor and linear drive mechanism to generate forces up to 60,000 lbs.

The design is inherently safer than the equipment requiring an explosive charge, since the power to operate the tool is provided by standard alkaline batteries.

The tool can be redressed quickly at the wellsite, and routine maintenance involves only lubrication and battery replacement.

The DPU is an electro-mechanical device that is designed to produce a bidirec-tional linear force for setting or retrieving downhole tools.

The DPU consists of three sections:

•The top section of the tool encloses the pressure-sensing activator.•The middle section is the control and power source.

•The lower section contains the linear drive mechanism.

The DPU has two operational modes. These are the tension (or pull) mode and the extension (or push) mode.

3.0 Procedure1. A gauge run should be made prior to running the DPU.2. Make up the DPU with the attached subsurface device and lower into the well

to the desired setting depth. The control circuit then initiates the setting opera-tion. With a stroke speed of approximately 0.7 in/min., The setting motion is gradual or controlled, allowing the sealing element to properly conform against the casing/tubing wall and the slips to full engage. When the sealing element is sufficiently compressed and the setting force is reached, the DPU shears loose from the subsurface device and is removed from the well.

3. See attachment on running and pulling operations.

Slickline Operations Manual SL 2.37: Memory Production Logging (MPL) Operations

SL 2.37: Memory Production Logging (MPL) Operations

1.0 ScopeSlickline run memory production logging tool.

2.0 General Information• An economical way to log a well on slickline rather than expensive electric

3.0 Procedure Run/Pull1. Gauge/dummy run.2. Need a technician to make up the tool - man in charge.

3. Run in hole to the desired depth.4. Slowly POOH as per technician.

02 Downhole

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