Slickline Operations & Procedures

• Title : Slickline Operations & Procedures
• Publish : AMERICAN PETROLEUM INSTITUTE Exploration & Production Department
• Type Document : pdf 
• Release : December 1994
• Total Page : 67 Page
• Size : 3.75 Mb

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CHAPTER 1 SURFACE EQUIPMENT

Wirelines have been in use since the early days of the oil and gas industry. The development of surface equipment for solid wireline operations has kept pace with the development of new methods and tools used in well completion, remedial and work-over operations. Solid wireline is used for depth determination, deviated hole surveys, temperature and pressure surveys, paraffin cutting, and cementing operations. Solid, wireline may also be used to set, retrieve, and manipulate chokes, circulating plugs, gage cutters, swaging tools, safety valves and gas-lift valves.
As the oil industry grew from the first shallow well in Titusville, Pennsylvania in 1859 to the first producing well on the Outer Continental Shelf in the Gulf of Mexico in 1947, wireline servicing also grew in complexity.Since then, wireline operations have kept pace with industry needs for work in deeper and more corrosive wells, deviated holes, and wells drilled in deeper water offshore.
The expansion of oilfield activities from conventional terrain to marsh, muskeg, desert and offshore locations has required mobility in wireline equipment for proper servicing. In the early days of solid wireline operations few problems occurred with mobile equipment. Trucks with wirelinewinches, skid-mounted equipment, and fixed units mounted at strategic locations handled most solid wireline work. The truck is now the primary transport vehicle for wireline land operations.
Wireline equipment was later moved to inland water and marsh locations by mounting the equipment on speed boats, tugs, or small barges. Today a diesel powered shallow water spud boat, with a built-in hydraulic system that controls the wireline spool as well as the boat spuds, is usually used in
bayous, streams, marshes or lakes.

As oilfield development moved offshore, equipment and methods oftransportation changed. Self-propelledjackup vessels are ordinarily used on shallow water locations. The jackup vessel is built on the same principle as a spud barge, except that the spuds are replaced with long legs to jack the boat out of the water. This enables the crew to work in rough seas and water depths of up to a hundred feet or more.

In remote offshore areas a specially designed skid-mounted diesel-powered wireline unit with built-in hydraulic pumps and motors is used. The unit is transported to the offshore platform or rig on a supply boat and lifted onto the platform by a crane.
Drilling and completion of oil and gas wells in desert terrain is accomplished by mounting the equipment on largewheeled vehicles (trucks or cars) capable of driving in soft sand. Wireline equipment is moved to desert locations the same way.
Weatherconditions in arctic areas call for specially designed cold weather units; however, these are also easily transportable by truck to remote locations.

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Completion Tech for Unconsolidated Form

• Title : Completion Technology for Unconsolidated Formations [ pdf ]
• Publish : Refferense by Coberly, C.J., “Selection of Screen Openings for Unconsolidated Sands”, API Drilling and Production Practice, 1941. Penberthy, W.L. and Echols, E.E., “Gravel Placement in Wells”, SPE Paper 22793, Journal of Petroleum Technology (July 1993) and Penberthy, W.L. and Shaughnessy, C.M., Sand Control, SPE Series on Special Topics, Volume 1, 1992.
• Type Document : pdf 
• Release : June 1995
• Total Page : 256 Page
• Size : 5.32 Mb

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CAUSES AND EFFECTS OF SAND PRODUCTION
Completion Technology for Unconsolidated Formations 2-1
Introduction
Chapter 1 addressed radial flow through porous media and showed the nature of the pressure distribution around a producing well. Negative effects on productivity caused by flow restrictions on the near wellbore area have been described. With the concepts of radial flow and formation damage understood, the problems unique to unconsolidated formations can be explored.
In highly unconsolidated formations, the production of formation fluids will probably be associated with the production of formation sand. In some situations, small quantities of formation sand can be produced with no significant adverse effects; however, in most cases, sand production leads to reduced productivity and/or excessive maintenance to both downhole and surface equipment. Sufficient sand production may also cause premature failure of the wellbore and well equipment.
 

Nature of Sand Production
The conditions which can cause sand production and the probable condition of the formation outside of the casing after sand is produced can be determined by the factors that affect the beginning of sand production. These factors must describe both the nature of the formation material and also the forces that cause the formation structure fail. The strength of a sandstone is controlled by:

• The amount and type of cementing material holding the individual grains together 
• The frictional forces between grains
• Fluid pressure within the pores of the rock
• Capillary pressure forces

The type of failure that is likely to occur in sandstone has been investigated by several researchers. Work at Exxon1 indicates that the nature of a failed perforation tunnel is indicative of a shear failure that will occur when the compressive strength of the rock is exceeded. In addition, the Exxon work indicates that in weakly consolidated sandstones, a void is created behind the casing. Exxon concluded that the rock’s compressive strength should be a good indicator of sand production potential, and that sand production will probably cause a void behind the casing that can be filled with gravel pack sand during a gravel packing operation. The details of the research work performed by Exxon may be found in Reference 1.

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Completion Hydraulics Handbook

• Title : Completion Hydraulics Handbook [ pdf ]
• Publish : Schlumberger - only for education reference
• Type Document : pdf 
• Release : December 2000
• Total Page : 392 Page
• Size : 5.76 Mb

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Chapter 4: 

HYDRAULIC FORCES and HOOK-LOADS

There are many different types of packers, each with its own considerations regarding forces. This chapter discusses, in general terms, the more common types of retrievable packers and how tubing and hydraulic forces affect them.
Tubing run packers are generally classified into two categories: 

• Single Grip Retrievable Packers  
• Double Grip Retrievable Packers

Single Grip Retrievable Packers
Single grip retrievable packers are the simplest and most economical retrievable packers. These packers have one set of slips that anchor the packer to the casing and hold the packer from moving in one direction only. Single grip retrievable packers are further classified into three basic types: 

• Non-Equalizing Tension Packer 
• Non-Equalizing Compression Packer 
• Equalizing Compression Packer

Non-Equalizing Tension Packer
The Model ‘SA-3’ retrievable packer is a typical example of a non-equalizing tension packer. The packer is set and packed off with tension pulled into it with the tubing string. It remains packed off so long as a tensile force is on the packer. Any force due to temperature or pressure which places compression on the packer will adversely affect the packer. As the name implies, this type of packer has no provision for equalizing differential pressure when releasing it. These packers usually incorporate a secondary shear release system activated by tubing tension.

Non-Equalizing Compression Packers
A typical compression packer of this type is the Model ‘CA-3’. The packer is set and packed off with tubing weight. A compression packer remains packed off as long as suitable compression is on the packer. Any force that works against this compression will tend to unset the packer. There is no provision for equalizing differential pressure across the tool.

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Advanced Oil Well Drilling Engineering

• Title : Advanced Oil Well Drilling Engineering by Dr. Bill Mitchell
  Mitchell Engineeering
• Publish : The Society of Petroleum Engineers of the AIME, PO Box 833836, Richardson, Texas, 75083-3836, USA.
• Type Document : pdf 
• Release : July 1995
• Total Page : 626 Page
• Size : 18.24 Mb

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TUBULAR DESIGN AND USE
GENERAL
The axiom of tubular design is that the loads placed on a tube by natural phenomena must be offset by its strengths. There are many natural phenomena which could dictate a particular tubular design. Also, there are many theories for determining the strengths of a tube. The tubular designer must therefore derive practical design equations from the theories and phenomena. These equations represent the "criteria for tubular design".
COMMON FAILURE THEORY ASSUSPTIONS
The most common simplifying assumptions with regard to tubular strengths are that the failure theory known as the MAXIMUM STRAIN ENERGY OF DISTORTION THEORY applies only to tubular collapse strengths and that only biaxial- loads are considered within the theory. Thus tensile loads and burst loads are thought to be uniaxial and strengths are rationalized with the MAXIMUM PRINCIPAL STRESS THEORY OF FAILURE. Design factors are usually based on experience. 

1. This theory predicts failure of a specimen subjected to any combination of loads when the portion of the strain energy per unit volume producing change of shape (as opposed to change of volume) reaches a failure determined by a uniaxial test. Refer to Strengths of Materials, by S. Timonshenko, reprint 1976, Krieger Publishing Company. 
2. Biaxial loads are those which result in the material of a structure being subjected to the simultaneous action of tension or compression in two perpendicular directions. Reference same as above.
3. Uniaxial loads are those which result in the material of a structure beingsubjected to the action of tension or compression in one direction only. Referencesame as above. 
4. This theory predicts failure of a specimen subjected to any combination ofnormal and shear stresses when the maximum principal stress, which is themaximum normal stress acting on a set of perpendicular planes which have noshear stress acting on them, reaches a failure value determined by a uniaxialtest. Reference same as above.

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Advanced Drilling System

• Title : Advanced Drilling System by John Crowther
• Publish : Anadrill Schlumberger
• Type Document : pdf 
• Release : December 1994
• Total Page : 109 Page
• Size : 1.11 Mb

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PowerPak Motors

1.1 Highlights
PowerPak is a positive displacement downhole drilling motor (PDM) powered by the circulating drilling fluid. The pressure drop across the motor is directly proportional to the drilling torque developed at the bit. The rotational speed depends primarily on the circulation rate, and is only slightly affected by the torque.

1.2 Details
1.2.1 Cross-Over Subs, Dump Valves, or Flex Subs
Cross-Over Subs (or Top Subs) are available for simple connection from the drill string to the stator/motor. Cross-Over Subs are available for all PowerPak motor sizes. A Dump Valve allows the drill pipe to fill with drilling mud when running a motor into a well, and to drain when pulling out of the hole. The valves close when the flow rate reaches a given threshold. Dump Valves are only available for motor sizes 4-3/4” through 11-1/4”. Flex Subs are available for 3- 1/8” through 9-5/8” motors. These replace the dump valve or cross-over and help prevent failure of the stator connections by reducing the bending stresses. Dump valves should only be run when required by the Client.

1.2.2 Power section
The power section, consisting of a stator and rotor, converts hydraulic power from the drilling fluid into mechanical power to rotate the bit. It operates by the reverse application of the Moineau pump principle. The stator is composed of an elastomer with a helicoidal lobe pattern cross section, with n lobes, molded inside a steel housing. The rotor is a machined stainless steel shaft, with a cross section similar to the stator, but with n-1 lobes. The contact of elastomeric stator lining and metal rotor surfaces forms continuous sealing lines and multiple closed fluid hambers. When drilling mud is circulated through the power section the rotor is forced to rotate. 

Rotors/stators are available in various configurations: with standard or extended length sections, standard or over-sized (OS) stators, and standard or undersize (US) rotors. Refer to the master orders for details. Chrome plated, tungsten carbide coated and non-plated rotors are available. Tungsten carbide plated rotors are recommended for salt-saturated or corrosive drilling muds.

1.2.3 Transmission section
This section transmits the rotary motion and torque produced by the rotor/stator down to the drive shaft/bearing section of the motor. The transmission couplings also convert the eccentric rotation of the rotor to concentric rotation at the bearing section. This section also includes the surface-adjustable bend housing. Heavy-duty transmissions are available for Extended Power Sections and special transmissions are required for 1:2, 2:3 and some GT lobe configurations.

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Advanced Blowout & Well Control

• Title : Advanced Blowout & Well Control by Robert D, Grace
  With Contributions By Bob Cudd, Richard S, Carden, and Jerald L. Shursen
• Publish : Gulf Publishing Company Houston, Texas
• Type Document : pdf 
• Release : December 1994
• Total Page : 414 Page
• Size : 11.11 Mb

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This excerpt is from an actual drilling report. Well control problems are difficult without mechanical problems. With mechanical problems such as those described in this report, an otherwise routine well control problem escalates into a disastrous blowout. It is common that, in areas where kicks are infrequent, contractors and operators become complacent with poorly designed auxiliary systems. Consequently, when well control problems do occur, the support systems are inadequate, mechanical problems compound the situation, and a disaster follows. 

Because this dissertation is presented as an Advanced Blowout and Well Control Operations Manual, it is not its purpose to present the routine discussion of blowout preventers and testing procedures. Rather, it is intended to discuss the aspects of the role of equipment in well control, which commonly contribute to the compounding of the problems. The components of the well control system and the more often encountered problems are discussed.

THE STACK
Interestingly, the industry doesn’t experience many failures within the blowout preventer stack itself. There was one instance in Wyoming where a blowout preventer failed because of a casting problem. In another case, the 5000 psi annular failed at 7800 psi. In general, the stack components are very good and very reliable.

A problem that is continually observed is that the equipment doesn’t function when needed. At a well at Canadian, Texas, the annular preventer had been closed on a blowout, but the accumulator would not maintain pressure. Two men were standing on the rig floor when the accumulator lost pressure and the annular preventer opened unexpectedly. As quick as the annular opened, the floor was engulfed in a fireball. Fortunately, no one was seriously burned. The source of the fire was never determined. The rig had been completely shut down, but the accumulator system should have been in working order.

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