01 00 Completions Basics (2)

Packer Systems (MKT-2112) Completions Basics

Completion Basics – What we will cover • Part 1 • Part 2

• Completion Space Out Practices

COMPLETIONS BASICS: PART 1

Completion: Definition

The objective of a completion is to convey fluids from the reservoir to the surface, in a safe and efficient manner.

Completion Design Systems Completion design requires knowledge of many systems: • Reservoir

• Surface Facilities • Casing & Tubing • Perforating • Downhole Completion Tools

– Flow Control System – Sub-Surface Safety System – Packer System – Sand Control – Inflatables – Liner Hangers – Instrumentation – Chemical Injection • Well Servicing and Workover

Reservoir Definition A porous, permeable rock body in which hydrocarbons have accumulated. • Geology determines the porosity,

permeability and the type of trap in which the hydrocarbons accumulate.

• Reservoir drive is the force that causes fluids

to flow from the reservoir into the wellbore

• A hole drilled into the reservoir provides a

conduit for flow to the surface.

Reservoir Considerations • Drainage

– Vertical – Horizontal – Extended Reach – Multi-Lateral • Number of Zones – Single – Multiple: • Selective • Co-Mingled

• Formation Interface

– – – –

Open Hole Slotted Liner Sand Exclusion Perforated Casing

Reservoir Considerations Flowing: • Reservoir pressure is greater than hydrostatic pressure created by the fluids in the wellbore. • Various methods used to maintain reservoir pressure: – Water injection – Gas injection Non-Flowing: • Reservoir pressure is less than hydrostatic pressure created by the fluids in the wellbore. • Various methods used to flow fluid to surface: – Decrease hydrostatic head – Pump fluids to surface

Reservoir Considerations Artificial Lift • Generally required • Supplements reservoir energy – Sucker Rod Pumping (80%)* – Gas Lift (10%)* – Hydraulic Pumping (5%)* – Electrical Submersible Pump (5%)* Exception • Prolific water drive * Percentage of Worldwide Artificial Lift Use

Artificial Lift Methods: Sucker Rod Pumping A method using a down-hole plunger pump which is driven by the surface pumping unit. • Rods are attached to the plunger pump. • On the surface, the rods are connected to walking beam. • The beam pivots back and forth, resembling a horse nodding it’s head, and moves the sucker rods in an up and down motion. • This motion is transferred to the pump downhole. • Movement of the plunger causes the well to unload its fluid. Operation (Pumping Cycle): • The downward stroke of the rods, the standing valve closes, the traveling valve opens, and fluid is forced from the working barrel through the plunger and into the tubing. • The upward stroke of the rods pulls plunger up through working barrel. The traveling valve closes, the standing valve in the working barrel opens and fluid enters the working barrel from the well.

Artificial Lift Methods: Sub-Surface Hydraulic Pumping A method using a bottomhole pump without sucker rods. The system of hydraulic pumping uses two strings of tubing: • Two strings installed beside each other. • A small string installed inside another. • Clean crude oil from the high pressure surface pump goes downward through the larger size tubing to the down-hole engine which moves a power piston connected to the production plunger in the bottom-hole pump. • Fluid from the well and the exhausted power oil become mixed and return to the surface storage through the smaller diameter tubing Operation: • Surface power is supplied from a standard engine driven high pressure pump. • Bottom-hole production unit consists of a downhole • Hydraulic engine directly connected to a plunger pump.

Artificial Lift Methods: Electrical Submersible Pumping A method of pumping oil using a downhole electrical pump. • Pump and motor suspended in well from surface or from Packer set in casing • Production flows up tubing, or is some cases up the annulus. Operation: • Downhole is a centrifugal pump and shaft that is directly connected to an electric motor. • Electric motor causes pump to revolve so that impellers in the pump apply pressure upon the liquid in it forcing that fluid through the tubing to the surface.

Artificial Lift Methods: Gas Lift A method of producing oil in which gas under pressure is used to lift the well fluids. • Specially designed gas lift valves installed on the tubing string provide openings between the casing and tubing. • Gas lift valves can also be ran in side pocket mandrels and pulled and replaced by means of a wireline unit. Operation: • Fluid that is standing in the tubing above the gas-inlet port is displaced, lightened by mixing with the injected gas and is raised to the surface by the expanding gas.

Reservoir Considerations Secondary Recovery Recover more hydrocarbons by increasing reservoir pressure, injection, displacement, or by means of creating a downhole reaction. • Waterflood

• CO2 Flood • Chemical Injection • Steam Injection • Fireflood

Casing & Tubing: Definition CASING: Pipe that lines the borehole. • Prevent caving of the hole. • Prevent contamination of fresh water zones. • Provide well control while drilling. • Provide smooth borehole of known dimensions. TUBING: Concentric pipe run inside the casing through which the hydrocarbons flow. • Provide isolation of fluid and pressures from the casing. • Provide well control, production control, stimulation control. • Provide a retrievable “replaceable” pipeline.

Casing Types • Conductor

– OD= 16-30”; Depth= 40-400’ • Surface

– OD= 7-20”; Depth= up to 1500’ • Intermediate

– OD= 7-13-3/8”; Depth= Varies • Production

– OD= Varies; Depth= Varies • Liner

– OD= Varies; Depth= Varies

Casing & Tubing: Specifications & Properties Specifications: • Joint Length • Outside / Inside Diameter • Drift Diameter • Threaded Connection • Pipe Thickness • Steel Grade / Alloy Type (CRA) – L80:

L - type of steel, 80- 80,000 psi MYS

Properties: • Burst • Collapse • Joint Yield Strength • Corrosion Resistance

Perforating: Function & Types Provide communication from formation to cemented and cased wellbore. Conveyance: • Wireline • Electrically Actuated • Thru-Tubing • Hollow Tube Carrier Casing Guns • Tubing Conveyed Perforating (TCP) Actuation Methods: • Mechanically • Pressure Actuated • Absolute • Differential

Downhole Tools: Function & Types Types: • Flow Control System • Sub-Surface Safety System • Packer System • Sand Control • Liner Hangers • Instrumentation • Chemical Injection

Considerations: • Temperature, Pressure, & Material Considerations • Tubing loads • Completion Installation – Actuation/Setting/Retrieving Method – Degrees of freedom

• Landing flexibility – Tension, compression or neutral?

• Compatibility

Flow Control Systems: Function & Types Devices that control the flow of fluids downhole. • Functions: – – – – –

Plug the tubing. Isolate zones. Check flow in either direction. Choke the flow in either direction. Selectively communicate between the tubing and the annulus.

• Types: – Tubing Mounted – Slickline, E-Line, Coiled Tubing Conveyed – Running & Pulling Tools

Flow Control: Seating Nipples & Blanking Plugs

Flow Control: Sliding Sleeve

Sub-Surface Safety Systems: Function & Considerations Surface Controlled Sub-Surface Safety Valve (SCSSSV)- Designed to shut-off tubing flow in the event of a catastrophe. • Considerations: – Regulatory requirements – Setting Depth • • • •

Crater depth Hydrate formation depth Kick off depth and angles “Fail safe” setting depth

– Subsea Completion

• Types: – Tubing Retrievable – Wireline Retrievable

Sub-Surface Safety Valve: Tubing Retrievable

Sub-Surface Safety Valve: Wireline Retrievable (Less Lock)

Sub-Surface Safety Valve: Tubing Vs. Wireline Retrievable Tubing Retrievable Advantages: • Largest cross sectional flow area • Allows insertion of wireline retrievable SCSSSV • More reliable than wireline type Disadvantages: • Requires rig to remove • May suffer from erosion during stimulation

Wireline Retrievable Advantages: • Retrievable w/o rig • Less expensive Disadvantages: • Reduced flow area • Must be removed during well servicing, leaving well unprotected • May be stuck due to scale build-up

Packer Systems: Function & Types Provides a seal between tubing and annulus at a fixed depth. Function: • Production Control • Production Testing • Protection of Equipment • Well Repair and Well Stimulation • Safety Types: • Retrievable • Permanent

Packer: Permanents & Seal Assemblies

Packer: Retrievable

Packer: Permanent Vs. Retrievable Permanents Advantages • Performance envelopes • Generally higher pressure ratings • Packer to tubing seals retrieved without packer • Hold pressure from above or below without set-down weight or tension Disadvantages • Must be milled over to retrieve • Not reusable

Retrievables Advantages • Retrievable without milling • Reusable • Some can be resettable

Disadvantages • Packer normally retrieved on production tubing • Generally smaller I. D.’s • Generally lower pressure ratings

Packer: Permanents Vs. Retrievables

Other Systems: Functions Sand Control • Prevent production of sand by means of a sand screen or gravel packed screen. Liner Hanger • Provide a polished bore receptacle for future “tieback” with production tubing. Inflatables • Provides a versatile sealing system for open hole, thru-tubing, and for a wide range of workover operations Continuous Injection System • Minimize or prevent corrosion by injection of chemicals via control line through downhole mandrel. Instrumentation • Manage reservoir by knowing pressure and temperature obtained from downhole gauges.

Remedial Systems • Well Stimulation – Hydraulic Fracturing – Acidizing

• Re-perforation • Fishing

• Remedial Cement Jobs • Zone Isolation • Water Shut-Off

• Secondary Recovery • Plug & Abandon

Completion Basics: Conclusion To design a completion, you have to be familiar with a lot of systems and how they relate to each other. • Reservoir • Surface Facilities • Casing & Tubing • Perforating • Downhole Completion Tools – – – – – – – –

Flow Control System Sub-Surface Safety System Packer System Sand Control Inflatables Liner Hangers Instrumentation Chemical Injection

• Remedial Systems

COMPLETIONS BASICS: PART 2

Completion Design: Reservoir • Drainage – – – –

Vertical Horizontal Extended Reach Multi-Lateral

• Recovery – Primary • Flowing • Artificial Lift

– Secondary • • • •

Pressure maintenance Waterflood CO2 flood Steam injection

• Well Type – – – –

Production Injection Disposal Storage

Completion Design Well Configuration • Number of Zones

– Single – Multiple• Selective • Co-Mingled

• Tubing Strings

– Tubingless – Single – Concentric – Dual • Formation Interface – Open Hole – Slotted Liner – Sand Exclusion – Perforated Casing

Completion Design Well Requirements • Tubulars – Tensile & Compressive Ratings – Burst & Collapse Ratings – Material Requirements • Downhole Tool Requirements – Pressure, Tubing Load, Temperature – Material Requirements – Tubing-to-Packer configuration – Packer Landing Flexibility – Installation Method – Retrievability

Completion Design Efficiencies • Wellbore Construction – Slimhole – Monobore – Setting Method – Number of Trips & Interventions required for setting

• Completion Installation – Number of Trips Required – Degrees of Freedom – Remote Actuation • "Work-Over” Flexibility • Intelligent Completions

Applications

SINGLE ZONE COMPLETIONS

Packer-less Completion • Simple. • One Trip. • Injection/Production. • Limited applications. • Well control issues

Mechanical Tension Set Packer • Simple. • One Trip. • Set with tubing manipulation. • Production/Injection mostly. • Tubemove required. • Medium to high pressure. • Moderate temperature.

Mechanical Compression Set Packer • Simple. • One Trip. • Set with tubing manipulation. • Production mostly. • Tubemove required. • Medium to high pressure. • Moderate temperature.

Hydraulic Set Packer Completion • Simple. • One Trip. • Hydraulic/Hydrostatic. • Injection/Production. • Tubemove critical. • Medium pressure. • Moderate temperature.

Seal Bore Packer Completion • Simple. • Two Trip. • Packer set with WL or tubing. • Production/Injection. • Tubemove required. • Medium to high pressure. • Moderate to High temperatures.

Fracturing/Stimulation Completion • Simple. • One Trip. • Packer set with WL or

tubing. • High tensile loads. • High differential pressures. • Tubemove required. • Normally run with an OnOff Tool above packer.

Fracturing Requiring Zone Isolation Completion • Packer set with WL or tubing. • On-Off tool above lower packer. This allows for temporary abandonment.

• Minimizes the number of trips. • No need to run a

retrievable or permanent bridge plug.

CO2 Injection and Waterflood Completions • Several options on packers. • Mechanically actuated shut-off valve above packer.

• No slick line required, no

plastic coating.

Applications

MULTIPLE ZONE COMPLETIONS

Multizone Waterflood Injector Completion • Multiple Packer. • Top tension packers just for isolation. • Waterflood mandrels and regulators between packers.

• Low cost.

Single String Selective Completion • Multiple trip completion. • Permanent or retrievable packers. • Sliding Sleeves between packers.

• Commingle or selective.

One Trip Single String Selective Completion • One trip completion. • Retrievable packers. • Sliding Sleeves between packers. • Commingle or selective.

Applications

DUAL COMPLETIONS

One Trip Dual Completion • Lower Single Hydraulic Set Packer. • Upper Dual Hydraulic Set Packer. • Production or Injection.

• Tubemove required. • SCSSSV.

One Trip Selective Dual Completion • Lower Single Hydraulic Set Packers. • Upper Dual Hydraulic Set

Packers. • Production or Injection. • Tubemove required. • SCSSSV.

Applications

GAS LIFT AND CHEMICAL INJECTION

Gas Lift • One Trip • Hydraulic set Packer. • Multiple GLM’s. • SCSSSV.

Chemical Injection • One Trip Hydraulic set Packer. • Chemical Injection Mandrel above packer.

Applications

HP/HT COMPLETIONS

HP/ HT Single Zone Completion • Multiple trip Completion. • 10,000 psi or higher. • 300°F or higher.

HP/ HT Single Zone Completion • Multiple trip Completion. • 10,000 psi or higher. • 300°F or higher. • Severe tubing movement

expected.

HP/ HT Single Zone Completion • One trip Completion. • 10,000 psi or higher. • 300°F or higher.

Applications

ESP COMPLETIONS

Single Zone ESP Completion • Multiple Feed thru

Hydraulic Packer. • Gas Venting and Gauge capable.

Single Zone ESP Completion • Non-Feedthru Packer. • Multiple trip completion. • Q-22 SS to control formation when retrieving ESP.

Single Zone ESP With Wireline Access • Naturally flowing lower zone. • Wireline access to lower zone. • Downhole monitoring

available. • Optional shut off devices such as the Q-22 SS may be run below lower packer.

COMPLETIONS BASICS: COMPLETION SPACE OUT PRACTICE

Completion Space Out Practices Spacing Out is determining the correct amount of tubing and pup joints required to land the tubing hanger with a compressive, tensile or neutral force on bottom. Topics covered: • Measurements

• Pipe stretch • Neutral, compression and tension space outs • Space out procedures • Specific tool space outs • Examples and problems

Completion Space Out Practices Measurements: What dimensions are critical? • Pipe Tally – Before you start, set up your tally book in columns of 10, 110, 11-20, 21-30… This makes it easier to add and trace a particular joint. – Domestically tally tapes are in feet and broken into hundredths of a foot – Measure pipe from the top of the box connection to the last thread buried when making up the pin end.

Completion Space Out Practices Measurements: What dimensions are critical? • Outside Diameter and Inside Diameter – Measure OD and ID on pipe, pup joints, crossovers and all completion equipment in the tubing string. – Measure OD and ID on flow control equipment, is 1.81” the minimum ID through a 1.81” nipple? – Record all other pertinent information about the tubing string and completion equipment, Total Joints on Location, Pipe Grade and connection, and serial numbers if applicable.

Completion Space Out Practices Measurements: What dimensions are critical? • Completion Equipment – Measure OD, ID and Length off all tools being ran including setting tools. – Draw and dimension a sketch for complicated hookups. – Measure internal lengths, how far will the seals sting into a packer?

Completion Space Out Practices Pipe Stretch • Pipe Stretch can be calculated or read directly off the

weight indicator. • Inches of Slack Off required for a given compression can be calculated, read from the weight indicator or looked up in a table. • Force on packer for a given slack off at surface is read directly from a chart, it demonstrates exactly how much force is reaching the packer.

Completion Space Out Practices Neutral Space Out • Neutral Space Out refers to having no weight on the packer. The

entire string weight will be supported by the hanger. • Calculate on what joint you should tag the packer, Record Pick Up and Slack Off weight a couple stands before tagging up. • If you see the seals enter the packer bore, then measure in the seal length, or slack off until you see the weight indicator drop off. Mark the pipe, pick up and slack off again verifying that you are located. Test the annulus. • Pull 1/2 the length of the seal assembly and test again, on long seal assemblies pull half of the remaining seals and test again. • If all the seals were in the packer bore Space Out from the original mark.

Completion Space Out Practices Compression Space Out • Compression Space Out means we will have some weight on the

packer. The tubing hanger and packer will be supporting the string weight. • Calculate on what joint you should tag the packer, Record Pick Up and Slack Off weight a couple of stands before tagging up. • Slack Off until you see the seals enter packer bore then measure in the seal length, or slack off until you see the weight indicator drop off. Slack Off the desired amount of compression. Mark the pipe and test the annulus. • Again pull 1/2 the length of the seal assembly and test again, repeat for long seal assemblies. • If all the seals were in the packer bore Space Out from the original mark.

Completion Space Out Practices Tension Space Out • Tension Space Out means the entire tubing string will be in tension.

The tubing hanger will be loaded by the string weight plus the tensile force applied to the packer. • Calculate on what joint you should tag the packer, Record Pick • Up and Slack Off weight a couple of stands before tagging up. • Slack Off until you see the seals enter packer bore then measure in the seal length, or slack off until you see the weight indicator drop off, set down to engage the anchor. Pull tension to verify that anchor is latched. Pull the required tension over the Pick Up weight. Mark the pipe and test the annulus. • Release anchor and space out to mark.

Completion Space Out Practices Space Out Procedures • The pipe should be marked at the slips/rotary from the previous operation.

• Measure the elevation (distance between the slips/rotary to the hanger hold down pins on the spool). Record this distance. • Pull the joint you tagged up with and measure from your space out mark to the last thread shouldered on the pin. • Pull 2-3 joints depending on elevation, number and measure them.

• Pull one more joint to be used as a slick joint and measure it also. • Total up all joints pulled including the partial length of the joint marked for space out. • Subtract the elevation, length of the slick joint, the portion of the tubing hanger from the pins down (if used), and the double pin sub if used.

• The remaining length will be compromised of pup joints. Add up various combinations of pup joints to get the required length.

Completion Space Out Practices Space Out Procedures • Make up pup joints directly to the tubing string, make up

the double pin sub if used, then make up the slick joint. • Make up the hanger or install the wrap-around, then bump up the landing joint “wrench tight”. • Land the tubing hanger, install the hold down pins and test.

Completion Space Out Practices Specific Tool Space Outs • On neutral or compression space outs when you land the tubing hanger your last motion will be down. Always mark your tubing for space out after you have made your last motion down. Especially in deviated holes with large differences between pick up and slack off. • With a tension space out you cannot install the tubing hanger until after the anchor is latched up. You have to latch up the anchor and then pull tension into the string. Set the slips, break out the landing joint, install the hanger and the landing joint. • To space out high, mark the pipe and space it out like the neutral space out. Subtract how far you want to space out high from your required length before you figure in the pup joints. Treat the desired high space out like a pup joint. • Most mechanical set packers are spaced out to the nearest joint. Mechanical set packers also require a certain amount of stroke to set. The stroke needs to be added on to the required compression. This will tell you how “high” you need to start setting the packer.

Completion Space Out Practices Examples and Problems: • Elevation: 64.50’ • hanger: 0.89’ • Double pin sub: 1.33’ • tagged up 29.30’ in joint 365 • 364: 31.60 • 363: 31.48 • 362: 31.51 • Lay out #1- 29.30 – #2-31.60 – #3-31.48 – #4- 31.51 (slick joint) – total=123.89 – elev 64.50 – subtract the slick joint 31.51 and hanger 0.89 and DPS 1.33 – total 25.66’ of pup joints

Completion Space Out Practices Examples and Problems How many feet of pups are required to space out the DB in neutral?

SPACE OUT PROBLEMS (1) We've got a R-3 with 30" stroke to be set at 8,000'. 2-7/8 tubing in 5-1/2“ casing. I want 15,000 lb at the packer upon setting. How far above the bowl on the wellhead should the hanger be when we slack off to set the packer?

SPACE OUT PROBLEMS (2) There's a Model "DB: RPP set at 10,000 ft. in 8-5/8"

casing. I've got 10‘ of seals on 2-3/8" tubing.

1. Briefly explain the procedure for testing my seals. 2. After bottoming out the locator seal assembly, how many inches do I come down in order to slack off 15,000 lb?

SPACE OUT PROBLEMS 3) There's a Retrieva-DB set at 7,500' in 7" casing. I'll be

stinging into the packer with an anchor seal assembly on 6.5 lb/ft 2-7/8" tubing;

1) What would the weight indicator read if I landed in neutral? 2) What would the weight indicator read if I flanged up with 15.000 lb tension? 3) Briefly explain the procedure for testing my seals.

After bottoming out the locator seal assembly, how many inches do I come down in order to slack off 15,000 lb?

SPACE OUT PROBLEMS 4) There's at Model "DB" RPP set at 8,500' in 9-5/8" casing. I'll be stinging in with a locator seal assembly on 6.5 lb/ft 2-7/8" tubing. I've got a single string hanger to be set at 800'. My weight indicator reads 60,000 lb when I pick up and 40,000 lb going down. Block weight is 1,700lb. 1) What would my weight indicator read if I want 10,000 lb slacked off on the Model "DB" when I set my hanger?

NIPPLE-UP PROBLEM #1 ABC OIL CO.

LEASE A

WELL #1

Old RKB 30' AGL (Above Ground Level) Top of top Collar to bee landed at 30" AGL (±6") Anchor Tubing Seal Assembly to be landed in Model "D" set at 5715.00' RKB, then 20,000 lb↑ tension left on tubing when tubing is landed. Tubing is 2-7/8: OD EU 8RD 6.5 lb/ft Grade J-55 Total tubing on location is 187 Joints, Total Length 5759.60' Tubing pup joints measure 4.74', 6.33', 6.42', 8.15', 8.37', 10.10' From bottom of tubing to bottom of No-go shoulder on Anchor Seal Assembly measures 1.15', Seals & Production Tube 7.15'.

How many joints of tubing & how many pup joints of what length should be used? 2. How much stretch will there be in tubing when landed? Disregard any effects of tension & temperature on tubing length. 1.

Last Col. of Tubing Tally Jt. No. Length (ft) 181 30.54 182 29.90 183 31.15 184 30.66 185 30.33 186 30.76 187 30.82 This is purely an exercise in working with Tubing Tally, pup joints, correction, etc. We recognize that there are a great many variations in procedures, all of which are customized to well conditions and customer requirements.

NIPPLE-UP PROBLEM #1 • In general we would normally latch into packer, pull

required tension, mark tubing at landing point, get loose from packer, substitute appropriate pups for marked landing joint, latch into packer again with landing joint, pull required tension, install the hanger, land tubing, & lay down landing joint. • PLEASE SHOW ALL CALCULATIONS!

NIPPLE-UP PROBLEM #2 BCD Oil Company

Lease B

Well #2

Packer is set at 7810.00' RKB (RKB 22' AGL). Top of solid Doughnut Hanger to be set at ground level. 7" 23 lb/ft Casing.. 2-3/8" 4.7 lb/ft N-80 Tubing. And a Locator Tubing Seal Assembly. Top of Tubing Seal Assembly to Locator 1.52 ft Top of Seals to bottom of Production Tube 7.25 ft We want 6000 lb↓ on packer. Tubing Hanger .5' below surface level. Total tubing on location 7919.5', a total of 259 joints. The last column of Tally Sheet looks like this. Pups on location are 4.62, 4.78, 8.12, 10.07, 2.04. Jt. No. 253 254 255 256 257 258 259

Length (ft) 32.05 30.27 31.76 29.64 30.26 31.46 26.74

NIPPLE-UP PROBLEM #3 XYZ Oil Company Lease W Well #3 Old RKB 30' AGL (Above Ground Level) Top of top Collar to bee landed at 30" AGL (±6")

Locator Seal Assembly to be landed on Model "D" Set at 6344.45' RKB, then tubing landed in neutral at packer when tubing is landed in surface tubing hanger. Tubing is 2 3/8" OD, EU 8RD, 4.7#/Ft., Grade J-55 Tubing pup joints measure 4.74', 6.45', 8.36', 10.74'. Total tubing on location is 207 joints, total length 6375.60' Seal Assembly from tubing to bottom of No-Go 1.37' Seals and Production Tube 7.15'. How many joints of tubing & how many pup joints of what length should be used? Last 5 joints Jt. No. 203 204 205 206 207

of tubing tally Length (ft) 30.25 30.65 30.33 30.76 30.82

This is purely an exercise in working with Tubing Tally, pup joints, etc. We recognize that there are a great many variations in procedures, all of which are customized to well conditions and customer requirements.

NIPPLE-UP PROBLEM #3 Problem is: 1. How much slack-off, in inches, is necessary on surface to get 6000 lb↓ on packer? Give the weight (lb) necessary on surface? 2. How many joints in hole? 3. How many pups of what length should be used PLEASE SHOW ALL CALCULATIONS!