Industri Migas: June 2013 | Oil and Gas Industries Blog

Thursday, June 27, 2013

Well Construction Process

Drilling Rig - Well construction process
The installation sequence for the components shown on the following drawing is summarized below. This is not intended as a complete procedure, but an explanation of the diagram only
  • The cellar is prepared (onshore).
  • The conductor string is installed by a surface rig or pile driving in preparation for the drilling rig commencing operations.
  • The well isspudded and the wellbore drilled to surface casing depth.
  • The surface casing string is run and cemented into place.
  • A casing head housing (CHH) is attached to the surface casing.
  • Drilling continues to the intermediate casing depth.
  • The intermediate casing string is run and the casing hanger is landed in the CHH.
  • The intermediate casing string is cemented.
  • The casing head spool (CHS) is installed onto the CHH.
  • Drilling continues to the production casing depth.
  • The production casing string is run and the casing hanger landed into the CHS.
  • The production casing string is cemented.
  • The tubing head spool (THS) is made up onto the CHS.
  • The well may be perforated by electric line casing guns, if required at this point (optional).
  • Tubing and completion components are run and spaced out.
  • The tubing hanger is attached to the tubing and landed in the THS.
  • At this point the packers may be set.
  • A back-pressure valve (BPV) is installed in the tubing hanger.
  • The drilling BOP stack is removed and the Christmas tree is nippled up.
If the well was not perforated prior to running the tubing, it may be perforated now using tubing conveyed perforating (TCP) guns or thru-tubing guns run on electric line.
Read more . . .Well Construction Process

Tubing Specifications

EU (external upset) tubing
Since it is always the tubing string in which slickline operations are carried out, it is necessary for the slickline operator to understand the specifications and tubing product options.

Generally identified by the outside diameter of the tube (the nominal description size). The internal diameter of the tubing is generally approximate or rounded up to the nearest full size.
The tubing grade indicates the strength and type of steel used to make the tubing. It is specified by a letter and number, e.g., H-40, J-55, C-75, L-80, N-80 or P-105. The lower the number, the softer the steel. The number signifies the tensile strength in 1000 psi, i.e., N-80 with a cross-sectional area of one square inch will withstand a load of 80,000 lb.
Weight per Foot
Determines the wall thickness of the tubing. Since the OD is determined by the nominal tubing size, i.e., thicker wall reduces the ID in heavy weight tubing.

The drift diameter is a means of ensuring the quality control on the tubing ID. The process involves passing a precisely machined bar through the tubing joint or string. All tubing and completion components run in the well must be drifted.

Common thread types include:
EU = External upset tubing joints incorporate a collar and an internal recess.
NU = Non-upset, but otherwise same as the EU.
VAM = A premium type thread seal with a collar and no internal recess.
Hydril CS = A premium connection with no collar and incorporating a metal-to-metal, three point seal system and no internal recess.
The following table shows a summary of the common tubing sizes:
Common Tubing Sizes and Drift Diameters

Read more . . .Tubing Specifications

Tuesday, June 25, 2013

Well Completion Equipment

Well Completion Equipment
There are many types and designs of completion equipment in common use in oil and gas wells. In addition to the tubing string and packer found in almost all wells, there are several other key completion components that may be required and a number of optional completion accessories to add functionality to the completion.

The tubing is a smaller diameter pipe installed inside the casing to carry the reservoir fluids to the surface. Wear from erosion (flow related) and corrosion (chemical attack) is confined within the tubing string to protect the casing. If necessary, the production tubing can be replaced during a workover operation when required.

Available in a wide range of sizes and types, packers are designed to isolate production zones and the casing annulus from well pressure. The main types available are:
  • Inflatable - typically used in open hole, low-pressure completions or in well intervention operations.
  • Mechanical set - set by tubing string rotation, not common in completion applications.
  • Hydraulic set - set with the application of hydraulic pressure, available in single or dual string configurations.
  • Wireline set - permanent packers can by set on electric line, with a seal assembly attached to the tubing and are configured to enable the tubing string to be inserted or stabbed into a polished bore.
Nipple profiles are installed at various intervals in the completion string to permit the installation of lock mandrels and flow-control devices during slickline interventions.

Circulation Devices
Circulation devices allow communication between the tubing and annulus or the formation and tubing. They are also known as sliding side doors (SSD) or sliding sleeves and generally contain a nipple profile at the upper end for contingency purposes.

Side Pocket Mandrels
Side pocket mandrels (SPM) are positioned in a completion to provide an injection point for lift gas or chemical inhibitors or provide a circulation facility for well kill purposes. A SPM allows communication between the tubing and annulus.

Blast Joints
Blast joints are externally hardened; heavy walled sections of tubing that are placed across the perforations of the upper zones to protect the tubing from abrasive wear.

Flow Couplings
Similar in appearance to blast joints but available in shorter lengths, flow couplings are installed above and below areas of reduced internal diameter, such as safety valves, to protect the tubing from internal erosion resulting from turbulence. Flow couplings are essential in high-rate gas wells.

Telescoping Travel Joint
Telescoping travel joints are installed in dual completions to assist in spacing out the second string and allow for thermal expansion of the tubing string.

Surface Controlled Subsurface Safety Valves
Surface Controlled Subsurface Safety Valves are available as tubing retrievable (TRSSV) or slickline retrievable (SLSSV) models and are installed on all offshore wells and some land wells. They are designed to secure the well in an emergency and are “failsafe” in operation, being normally held open by hydraulic pressure and closing automatically if the operating system pressure is released.
Read more . . .Well Completion Equipment

Back Pressure Valves

Back Pressure Valve
Back pressure valves are installed in the tubing hanger to hold pressure from below during the following operations:
• Nipple down and up the drilling BOP stack.
• Nipple up or down Christmas tree.
• Test the Christmas tree (2-way check).
• Replace the master valve.
The most common types of BPV are the Cameron Type ‘H’ BPV and Petroline ‘ABC’. A BPV is set in a profile provided in the tubing hanger using a special tool and lubricator assembly for threaded BPV models, or by slickline for profile set models. The BPV holds pressure from below to isolate well pressure, but allows flow from above to permit killing of the well if necessary in an emergency, i.e., the BPV functions as a check valve. A two way check valve is designed to fit the same profile as the BPV. It holds pressure from both directions while allowing equalization when required and is used to test the tree and BOP assembly.

Cameron Type ‘H’ Back-pressure Valve

Type H back-pressure valves are used extensively in Cameron hangers to safely seal well pressure to 20,000 psi during removal of the blowout preventer and installation of the Christmas tree. Fluid may be pumped through the BPV. If the tree above the BPV is to be pressure tested, the type ‘H’ 2-way check valve may be landed in the tubing hanger for pressures to 20,000 psi. If during the life of the well it becomes necessary to remove the Christmas tree or repair the lower master valve, the back pressure valve can be reinstalled in the hanger without killing the well. The lubricator consists of a rod, which works through a yoke provided with two stuffing boxes. By closing the vent valve and opening the equalizing valve, well pressure acts on both the top and bottom of the rod. The rod can then be moved up or down by means of a friction wrench. Experienced operators can utilize the well pressure in moving the rod by manipulation of the valves.

The running tool is inserted into the left-hand thread at the top of the valve, and then attached to the polished rod. When the valve has been lowered into the hanger, the rod is lowered so that the cross pin in the running tool engages in the slot on the top of the valve. Right hand (clockwise) rotation is applied to insert the valve. Once the valve is fully seated, moving the rod up to lift the pin from the slot and continuing a right hand rotation backs out the running tool. The pulling tool is attached to the rod and lowered to the valve. Left-hand (anti-clockwise) rotation makes up the pulling tool and then removes the valve.
Read more . . .Back Pressure Valves

Monday, June 24, 2013

Wellhead Valve Operating Precautions

Wellhead and chrismast tree configuration
The valves must be operated carefully when opening or closing. Some valve types have a shear pin between the handle and stem, which will shear to protect the valve’s internal components, if excessive force is applied. The master valve should not be used to close in a flowing well, except in an emergency. The swab or wing valves are typically used. Each time the gates of the valve shut in a flowing well, the increase in velocity of the well fluids during the closing action can cause wear across the seal faces. It is easier and safer to replace the seats and gates in valves, other than the master valve in the tree. Always count the number of valve turns made when closing. This is a prudent check against jamming the toolstring or wire in the tree, in the event that the tools have been raised fully into the lubricator.

Tubing Hanger
The tubing hanger is the device that supports the production tubing within the tubing head. A seal assembly on the body of the tubing hanger provides a hydraulic seal between the tubing hanger and the body of the tubing head. Tubing hangers, in most circumstances, are designed with an extended neck which seals in the bottom of the adapter flange to isolate the well fluids from the tubing head ring joint seal.

Internal profiles on the tubing hanger provide a means for inserting a tubing back-pressure valve (BPV). The body of the tubing hanger is ported for the routing of a small control line that is connected to the sub-surface ball valve. The threaded connections top and bottom of the tubing hanger are compatible with the tubing string being suspended. In the lifetime of the wellhead, the tubing hanger is the component that will most commonly be removed and replaced.

Christmas Tree
The Christmas tree is an assembly of valves and fittings used to control the flow of the well fluids and provide access into the tubing string or production conduit. The adapter flange is the connection on the bottom of the Christmas tree that mates with the top flange of the tubing head and is of the same size and pressure rating of the tubing head flange.

The internal profile of the adapter flange accepts the extended neck of the tubing hanger, with some designs of adapter flange the profile will include a secondary seal. Around the outside of the bottom flange are a series of fittings for test ports and bleeder ports. These ports are used to energize the secondary pack-off and perform a ring joint test between the two mating flanges, the lower annulus seal, and the secondary pack-off. To match up with the porting on the tubing hanger neck, an additional port is used for the control line fluid to pass to the downhole safety valve. The top connection is used for the first valve of the Christmas tree. In a bolt-up style of tree, normally the adapter flange is integral to the Christmas tree valve and termed as part of the Christmas tree unit.

In a composite style Christmas tree, the adapter flange will form the bottom flange of the Christmas tree.
Read more . . .Wellhead Valve Operating Precautions

Surface Equipment : Well Head

Chrismast Tree - Well head, Single Composite Tree
The surface connection of the wellbore is to the Christmas tree, a series of valves installed on the wellhead to control the flow of fluids from the well. There are many types and designs to suit the wellsite and reservoir fluid conditions. Wellhead pressure, fluid type, corrosive content, temperature and available space, are some of the parameters affecting the choice of tree or valve design and specification. It is important that slicklineline operations personnel are familiar with the basic types options available.

Single Composite Tree
Used on low pressure (up to 3000 psi) oil wells; this type of tree is in common use worldwide. The number of joints and potential leakage points make it unsuitable for high-pressure applications or for use on gas wells. Composite dual trees are also available but are not in common use.

Single Solid Block Tree

For higher-pressure applications, the valve seats and components are installed in a one-piece solid block body. Trees of this type are available up to 10,000 psi or even higher if required.

Dual Solid Block Tree
For dual tubing strings, the solid block tree is the most widely used configuration. The two options shown are the most common designs. The valves controlling the flow from the deeper zone, the long string, are the lower valves on the tree. While there are some exceptions to this convention, unless the tree is clearly marked it can be assumed that the valve position reflect the subsurface connections.

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Read more . . .Surface Equipment : Well Head

Drilling and Casing the Wellbore

Drilling and Casing the wellbore - figure 1
Prior to a well being ‘spudded in’, a conductor (large casing) is placed in the surface formation to provide a starting point for drilling operations. On land wells, a cellar may be constructed and the conductor driven into the ground with a pile driver. Alternately, a post hole type boring rig may be used to make a hole in which the conductor can be cemented. On offshore wells, the conductor is typically installed in slots designed into the platform structure. The well is drilled in stages and cased to prevent hole collapse and the movement of formation fluids into the wellbore. The number and size of casings is determined by the final well depth, formation conditions and final well pressure and service (oil or gas, single or dual, etc.).

The diagram in Figure 1-1 Drilling and Casing the Welbore shows a typical three-casing onshore well. With each casing string being cemented in place, the formation conditions and well location determine how much cement overlap is
applied in each casing string. A good cement bond between the formation and casing is essential to prevent the migration of fluids between the producing zones or to the surface. This can be checked or confirmed by running a CBL (Cement Bond Log) run on electric line before continuing with the next stage of drilling and completing the well.

Care is taken at all phases of drilling to ensure that the surface facilities are isolated from the downhole formation pressures. This is achieved by the density of the drilling mud (creating hydrostatic pressure in the wellbore to balance formation pressure) and the use of blowout preventers (BOP). The BOP stack is mounted immediately below the rig floor on land wells and jack-up rigs. On semisubmersible rigs and subsea completions, the BOP stack is mounted on a template on the seabed.

The wellbore is drilled to a depth just below the area of strata where the oil or gas is trapped. This area is known as the reservoir formation and is usually a layer of sand, shale or rock, which contains the gas or oil. The thickness of the reservoir can vary from only a few feet to several hundred feet or even several thousand feet in prolific fields.

To allow the reservoir fluids, i.e., oil and gas, to enter the wellbore, perforations are made through the casing within the reservoir interval. The perforating gun is generally lowered into the wellbore on electric wireline. Alternately tubing conveyed perforating systems permit the running of the perforating explosives with the production tubing string. After confirming proper placement, the perforating gun is fired electrically from the surface or in the case of TCP, a drop bar may be used to detonate the guns.

When the perforating gun is fired, a perforation tunnel is created through the casing and cement sheath and into the reservoir formation. This provides clear channels through which the oil and gas can enter the casing, where it is produced to surface through the production tubing. During the completion phase of a well, the production tubing and packer are installed. Production tubing is a smaller diameter pipe, which is lowered inside the casing to a point somewhere above the perforations. Attached to the lower end of the tubing, is the production packer.

The packer incorporates slips (teeth) to secure the packer in place and one or more sealing elements to provide hydraulic isolation. With the tubing and packer are at the desired depth, the slips and the rubber seal elements on the packer are activated, usually either by rotating the tubing or by applying hydraulic
pressure through the tubing bore. This causes the slips on the packer to expand and bite into the casing and also causes the rubber seal elements of the packer to expand and seal off against the internal diameter of the casing. With the packer anchored in place, the gas and oil enters the casing through the
perforations and flows up to the packer, where it enters the production tubing and flows to surface.

The tubing-casing annulus is the space between the outside diameter of the tubing and the inside diameter of the casing above the packer. This space is generally filled with fluid, such as water or brine containing a corrosion inhibitor, to protect the tubing and casing from corrosion. The hydrostatic pressure (weight) of the annulus fluid tends to hold the packer in place and also provides a means of killing the well, when necessary, by admitting the annular fluid into the tubing string.

Some wells are constructed with a liner. This option requires a smaller hole and does not require a casing string to run all the way to the surface, representing a significant cost saving in drilling time and casing costs. The liner hanger system supports the liner off the bottom of the well until the cementing operation is completed. Liner hangers can also be installed when an existing well is worked over and the depth increased.

Read more . . .Drilling and Casing the Wellbore

What is Slickline Operations ?

Slickline Operation
The term Slickline relates to the use of a wire or braided line to convey downhole tools or equipment in a wellbore. The first use of wire in a wellbore was as a measuring device. In the construction of the early wells dug by hand, sticks were used to measure depth. The stick was laid on the ground and the distance/length stepped off. Occasionally, for important measurements a surveyor’s chain would be used. To create a hole in the ground, early drilling operations used a pointed tool on a rope. However, as the work progressed, the rope stretched and often broke. The length of the rope could not then be used as an accurate measure.

To overcome the weakness of rope, wire cable was used. By this time, a method had to be devised to measure the depth of the hole. Normally the hole had water in it to help soften up the dirt, clay sandstone or limestone rock. If the driller used a rope with markings, the rope would be wet as it came out of the hole and would rot while being rolled up on a winch type spool or drum. The drillers started using cable, but it was bulky and as it stretched going in the hole, the weight of the cable either broke it or stretched between the markings on the cable.

Around the same time as the use of rope and cable, some drillers were using a flat steel tape with markings on it. The tape would be lowered into the wellbore, however, it suffered the same problems as the cable and rope, as weight exceeded the strength of the tape cross-section, it would part. The subsequent use of wire offered several advantages. It weighed less than a cable, was easier to handle than a rope and the length or depth to which the wire could be used was be greater. This was accomplished by putting the wire on a drum, which could be lowered and raised by a winding handle. As the wellbores increased in depth, a winding handle with a gear ratio was added to pull up the greater weight. By this time, a brake hand was added to the other side of the drum to control the speed of the line going in the hole. The principal power source at this time was steam and a steam operated engine was used to pull the line out of the hole.

The first noted use of slickline was by Halliburton to follow a cement plug down while cementing a well. These units were originally mounted on the rig, although they later became part of the equipment of the service engineer and were operated off of the left rear wheel of a car or pickup truck. From this early efforts a unit known as a side-winder was developed – a spool of wire on a drum would slide out on a frame from the bed of a pickup truck. The left rear wheel was jacked up, a sheave, drum or cathead was attached and a rope was run around it to the drum of wire. This was prevalent in the 1940’s.

The operator told the helper how fast to run the engine and winch, the helper being positioned in the cab of the truck with his foot on the gas pedal! There was no weight indicator and the operator had to guess how much he was pulling on the wire by how far he could push down on it. To measure how deep he had gone in the hole, the operator would count the number of layers of wire that had gone in the hole and come up with a figure for depth, determined by the circumference of the drum. This was a crude guess, but an experienced operator would generally be off only 5 to 10 ft if measured by a counter.
From that method came the skid units with belt drives and clutches to improve control of the winch. A counter head and a device to measure the amount of pull (weight) on the wire had been developed by this time. The counter head was developed by Halliburton and the OD of the wire determined the size of the wheel in which the wire ran. To measure the pull on the wire, there were two methods, electric and hydraulic. Much of the same principals are still applied in the design and use of modern slickline equipment. However, with increased wellbore depths and the growing complexity of downhole completion equipment, the applications for slickline have increased significantly. Almost every wellbore will at some time be accessed by slickline. Even highly deviated or horizontal wells can require slickline access for the installation or servicing of upper wellbore components. Slickline (and occasionally braided line) is commonly used in the following operations:

• Checking the production tubing drift
• Checking the build up of wax, scale or wellbore deposits
• Confirming the well depth or clearance to perforations
• Running and pulling plugs or flow control devices
• Opening and closing sliding side-doors or similar completion equipment
• Conducting pressure and temperature surveys using mechanical or electrical gauges and recorders
• Installing tubing pack-offs or similar completion devices
• Logging and perforating

The majority of blowouts and pressure related incidents are caused during well intervention, using equipment and techniques such as slickline, CTU, snubbing or workover rig operations. Efficient, safe slickline operations are essential, but can only be achieved through good planning and implementation of correct procedures. The use of appropriate tools and correctly maintained equipment is an integral part of successful, safe, slickline operations. The necessary skills and operator competency are a result of thorough theoretical education and practical training.

Read more . . .What is Slickline Operations ?


The advent of horizontal drilling brought new and unexpected challenges with respect to characterizing flow regimes in horizontal wells. New approaches to logging, fluid flow interpretation and evaluation, and wellbore configuration were developed in response to those challenges. One obvious problem presented by the horizontal wellbore was that wireline tools could no longer be pulled to total depth by gravity. As borehole inclination approaches sixty degrees from vertical, friction increases to the point that wireline tools cannot freely fall to the bottom of the well. In this horizontal environment, gravity is no help at all. This unit will discuss some of the methods that were devised to overcome this problem.

As with vertical wells, it was necessary to identify commercially productive perforations, as well as to determine which intervals produced water. However, the results obtained by conventional production logging tools were generally not sufficient to characterize horizontal flow regimes. These conventional tools were designed to measure vertical flows, in which fluid phases are dispersed with near uniformity across the wellbore. With few exceptions, conventional production logging tools were not capable of characterizing horizontal flow in any detail. This experience prompted the study of horizontal flows in order to develop logging tools capable of discerning each phase within the flow.

The problems encountered in horizontal wells were not merely related to flow patterns and downhole tool designs. The broad application of slotted liners, gravel packs, and external casing packers pose problems in understanding and characterizing flow in horizontal wells. Through such configurations, fluids can move both within the casing or liner, and through the annulus. As a result, the point at which a logging tool detects a sudden inflow into the borehole may not, in fact, mark the actual source of the fluid entry. This unit focuses on current methods of measuring multiphase flow in horizontal wells. Though current technology has not addressed all of the problems associated with horizontal production logging, oil companies and logging companies continue to study the nature of multiphase flow downhole, and seek to develop more accurate tools to characterize flow in horizontal wells.

Horizontal Well Configurations

What is horizontal well ?
The term "horizontal well" is very loosely used in the industry, since no well is ever completely horizontal, except over the course of short intervals. In this discussion, the term "horizontal well" will encompass any well that is horizontal (90 degrees of deviation), near-horizontal (within 10 degrees of horizontal), or undulating (deviation fluctuates above and below 90 degrees). The important factor to recognize is that in a "horizontal well" a change of only a few degrees in inclination (e.g. changing from 88 to 90 or 92 degrees from vertical) can make a dramatic difference from a production logging perspective. The angle affects which fluid phase (heavy or light) will be dominant within the cross section of the wellbore. A slight change in well angle can dramatically affect individual phase velocities.
Fluid identification logging tools are sometimes used to determine which fluid phases are present within the wellbore, and to measure each fraction at any point along the wellbore. Under ideal conditions, if such a tool provided excellent and reliable information within the horizontal environment, then the character of the logs would be much more affected by the well inclination than the entry profile. In vertical wellbores, the fluid identification tool provides an important indicator of fluid entry, but in horizontal wells, these indications could be misleading in the absence of other amplifying information; especially the directional survey.


Saturday, June 22, 2013

Casing Potential Surveys - Casing Inspection

illustrates a well casing - figure 1
 Casing potential surveys detect electrochemical corrosion as it occurs; hence, these tools indicate where damage from corrosion is imminent. The schematic of Figure 1 illustrates a well casing in which certain parts of the casing act like anodes relative to other sections of pipe, which act like cathodes.
Those sections that appear as anodes are undergoing electrochemical corrosion and metal loss. Casing potential surveys locate these intervals and assist in developing cathodic protection operations to protect these wells. A log showing the casing voltage or potential profile. A positive slope indicates a cathode, and a negative slope indicates an anode (interval of metal loss) Run 1 indicates that the intervals from 1495 to 1650 ft (456 to 503 m) and from 1700 to 1850 ft (518 to 564 m) are anodes, and hence are corroding. In Run 2, cathodic protection is being used by putting a current to the wellhead of five amps. Two areas are still found to remain anodes by the casing potential survey. At eight amps, Run 3 shows that the whole casing string is now a cathode, and therefore such electrochemical corrosion is minimized or eliminated.
Acoustic Casing Inspection
Acoustic casing-inspection tools are basically modifications of the pulse-echo cementbond tools. The geometrical parameters indicated in that section are presented, plus an analysis of the frequency response of the signal appearing in the gate W2. The frequency analysis is conducted to determine the wall thickness of the pipe. The kind of information available from these tools, (e.g.Schlumberger CET) includes measurements of ovality, minimum and maximum radius, internal diameter, and minimum and maximum wall thickness.

Newer-generation tools, such as Halliburton’s Circumferential Acoustic Scanning Tool (CAST-VTM ) and Schlumberger’s Ultrasonic Imager (USITM ), provide full 360 degree coverage of the wellbore profile in a range of presentation formats. Cased hole applications include both ultrasonic cement evaluation and pipe inspection.
Read more . . .Casing Potential Surveys - Casing Inspection

Casing Inspection : Corrosion Investigation

Corrosion logs include mechanical, electromagnetic, acoustic, and electropotential measurements. These are used to :
• monitor pipe wear caused by continued drilling operations
• detect corrosion on the inside or the outside of the pipe
• locate holes and pits
• detect split or parted pipe
• detect collapsed pipe
• locate perforations
• determine where electrochemical corrosion is likely to occur

The tools for these logs are generally sized to match the casing to be inspected, and hence are not through-tubing devices.

Mechanical Calipers

Mechanical calipers are of two basic types. The bow-spring type caliper ( Figure 1 ) is typically run with a flowmeter, and is used to monitor the inside of the pipe.
Mechanical Caliper - Figure 1
Its use is critical when restrictions such as asphalt, paraffin, or scale buildup are likely. It is also routinely used in openhole completions where a flow profile with a flowmeter is required. The other is the multifinger type, with anywhere from 40 to 80 individual fingers. As these fingers scrape the pipe wall, their maximum deflection is monitored. A single measurement of the maximum deflection among all of the fingers is most common, although some tools are capable of providing a maximum and minimum indication, or of examining individual angular sectors of the wellbore—e.g., a minimum and a maximum for each 120o (one-third) of the casing wall. Figure 2 shows a schematic of this type of tool, along with a typical log response.
This example is a Dialog Company multi finger caliper recorded with a pen recorder, and hence the deflections are arced in character. The multi finger calipers offer good detail of the inside of the casing and are accurate for measurement of percent wall penetration.

Multifinger Type Caliper - figure 2

Electromagnetic Casing Inspection
The electromagnetic tools fall into two categories: those that saturate the casing with magnetic flux lines and measure the distortion of those lines by a defect, and those that measure the amount of metal remaining by measuring the phase shift between two coils. Both types of tool inspect both the inside and the outside of the pipe. The tools that measure the distortion of flux lines by defects in the pipe wall are padtype devices. The most modern of these devices record each pad directly. The service companies and their trade names for this service are as follows:
· Schlumberger Wireline and Testing Pipe Analysis Log (PAL or PAT)
· Western Atlas Vertilog
· Halliburton Energy Services Pipe Inspection Tool (PIT)

These devices are hereafter referred to as pad-type casing inspection tools. The schematic of Figure 3 shows the pad tool.
Pad-type Casing Inspection Tool - figure 3
Inside the tool is a coil, which generates a magnetic field whose flux lines are parallel to the casing axis. Inside each pad is a coil which generates a current as it passes over a point where the flux lines are distorted into the wellbore. This occurs at a pit or hole in the pipe, even if the pit is located on the outside of the pipe. Surface roughness has the same effect, appearing as a lot of pits. The pads are also equipped to highlight defects appearing on the inner surface. With this information, defects on the inner or outer surface of the pipe can be detected.
The test, which responds to defects on either the inner or outer surface of the pipe (or within the metal), is sometimes called the flux leakage test. These tools have an upper and lower array of pads to ensure complete wall coverage. The flux leakage for the upper and lower pad arrays are labeled FL-1 and FL-2 on the log. The track labeled "discriminator" shows the measurement of the internal wall condition only. It is apparent that the interval from 4793 to 4870 ft (1401 to 1484 m) shows general external corrosion, since the inner wall is clear of defects except for the intervals noted. The track labeled "average" shows the average of all of the FL-l and FL-2 responses as seen by the pads. If the defect is large, it is detected by many or most of the pads and therefore shows a large average. A single-point defect shows a small average reading.
Read more . . .Casing Inspection : Corrosion Investigation

Saturday, June 15, 2013

Pulsed Neutron Capture Logging - Oil and Gas Industries

The pulsed neutron capture tool is used to determine water saturation in formations having high water salinity. The range of applicability for determining water saturation is generally a minimum of about 15% porosity, with a formation water equivalent sodium chloride salinity of at least 50,000 ppm. New tools and repeat runs can reduce the statistical error inherent in a nuclear tool, correspondingly reducing these limits. For purposes of comparison with earlier logging to detect changes in saturation, these limits may be reduced even further, since such comparisons are not intensely quantitative. Be sure to consult with the wire-line service company prior to running any pulsed neutron capture logs if conditions are at or below these limits. Some of the more recently developed tools (e.g., Schlumberger’s Reservoir Saturation Tool, or RST) can be run through tubing. Schlumberger’s RST also has carbon-oxygen (C/O) measurement capabilities, and so can be used in environments of low or unknown water salinity.

Pulsed Neutron Capture Hardware

Pulsed neutron capture logging tools are typically small-diameter through-tubing tools, 1 11/16 in. (4.29 cm) diameter or less. These tools include an electronically activated neutron generator, which periodically emits bursts of 14 MEV neutrons, at rates ranging from 800 μs to 5000 μs between bursts. The burst rate varies with the service company and tool model. All modern tools have a near (short-spaced) and a far (long-spaced) detector that count gamma rays associated with neutron interactions with the formation. Figure 1 shows a schematic of this tool The detectors are typically sodium iodide crystal scintillation detectors and do not discriminate with regard to gamma ray energies. As a result, the tools also measure a background count rate to distinguish natural from induced gamma rays. At present, the main industry versions of the pulsed neutron capture log are the following:
Figure 1 - Logging tool pulse.
  • Schlumberger Wireline & Testing: thermal decay time log (TDT-K, TDT-M, TDT-P); as noted above, Schlumberger has incorporated pulsed neutron capture and carbon-oxygen measurements into the reservoir saturation tool (RST).
  • Halliburton Energy Services: thermal multigate decay time tool (TMD-L).
  • Western Atlas: reservoir monitoring system (RMS).

Other types of pulsed-neutron capture tools are available, and may be obtained from smaller
independent service companies.

Read more . . .Pulsed Neutron Capture Logging - Oil and Gas Industries

The Logging Environment

Figure 1 - Logging Environment
Zones A, B, C and D are porous, permeable zones containing fluid; these are separated by impermeable shales. Casing is cemented into the borehole across the entire interval; each zone should be hydraulically isolated. Zones A, B, and D have been perforated to establish communication with the formations. (When a number of zones are perforated in the same wellbore, as shown in the figure, the zones are said to be commingled.) The completion results shown in this figure indicate some problems with this well. Zone A is producing, whereas zone B is not. Zone B is "stealing" fluid production which would otherwise be produced to the surface, and thus is said to be a thief zone. From the inside of the wellbore, it would appear that zone D is producing properly, although examination of the figure indicates that this is not the case. A defect in the cement job has allowed communication between zones C and D, and the result is a "channel" in the cement through which zone C is produced. From the schematic, it is not clear whether zone C is just producing or is also flooding zone D.
These problems—the sources and losses of production, the presence of channels, and the possibility of zone C flooding zone D—are the types of issues addressed by cased-hole logging techniques. Cased-hole operations present special problems not seen in openhole logging, especially especiallly with respect to formation evaluation. Again, it is clear from Figure 1 that the logging tool is not adjacent to the formation, but instead is inside the pipe which, in turn, is separated from the formation by cement or by a channel. The channel may be filled with mud, water, oil, or gas, and cement of unknown thickness may be present. Certain tools are serious1y affected by wellbore fluids. The region below the lowest perforations (the rathole) may be filled with water, while the wellbore immediately above the perforations across zone D is filled with oil. Apparent gas entry from zone D has caused the wellbore fluid above this zone to become gas-cut. There are clearly many variables in the wellbore environment that affect the response of cased-hole logging tools.
One way to classify cased-hole logs is by their Primary area of investigation. Moving from the center of the wellbore in Figure 1 , four regions are encountered: the inside of the well-bore, the casing wall, the annulus between the casing and the formation, and the formation itself (labeled by Roman numerals I, II, III, and IV, respectively). A cased-hole logging tool is generally designed to investigate one of these four regions. Flow evaluation devices measure fluid movement inside the well-bore; casing inspection surveys examine the pipe itself; cement-bond logs scan for cement annular fill; and formation evaluation sensors measure the shaliness, porosity, water saturation, and other formation properties. Each sensor, while having a primary region of investigation, may be secondarily or adversely affected by the other regions.

Read more . . .The Logging Environment

Logging Operations

We may divide cased-hole logging operations into two groups: those in which the tools are run through tubing and those in which they are run in casing. Throughtubing tools include those designed to evaluate flow conditions downhole, along with certain nuclear tools. Most other tools are larger in diameter and are used before placing tubing into the well (such as for cement-bond surveys), or after pulling the existing string.
Logging Operation

  1. Logging truck
  2. Mast truck—The mast hydraulically folds up and down for easy transport to and from location. The mast may be part of the logging truck, especially when logging pumping wells.
  3. Wellhead with valves on top
  4. Lubricator, or riser pipe—The logging tool is placed in the lubricator; the pressure in the lubricator is equalized to that of the wellhead pressure, the wellhead valves are opened, and the logging tool is lowered into the well. At the completion of logging, the tool is raised into the lubricator; the wellhead valves are closed, and pressure is bled down before the tool is removed. Note that a number of riser pipe sections may be connected to accommodate longer tool strings.
  5. Cable—This is usually a single-conductor armored cable (monocable). This cable is wound onto the winch of the logging truck for storage.
  6. Pressure bleed-off hose to relieve pressure from the lubricator after the job
  7. Grease line to maintain the grease seal
  8. Grease pump and reservoir for the grease seal
  9. Grease seal—Grease is injected into the small annulus between the cable and the seal tubes to effect a pressure seal around the cable.
  10. Instrument truck—This unit may or may not be required, depending on the instruments run.
  11. Prssure bleed-off hose—This is where pressure is released from the lubricator.
  12. Upper and lower sheave wheels—Note the lower sheave wheel chained to the wellhead.
  13. Flare line—Gas may be flared, or produced into the flowlines. Liquids may be produced into stock tanks or flowlines.
On through-tubing surveys, it is sometimes preferable (subject to safety considerations) to run the logging tool down through the tubing with the well flowing. This ensures that the interval being evaluated is stable in terms of production and fluid saturation.
Certain small-diameter logging tools may be run in rod-pumped wells. This requires a special wellhead that has an access for a wireline tool to be run in the tubing/casing annulus. The tubing anchor must be removed so that the tool can easily fit into the completed interval. The pump should be placed 50 to 100 ft (15.2 to 30.5 m) above the top producing interval, and the well should be stabilized prior to logging.
Depth control in a cased hole is achieved by running a gamma ray and collar locator, typically at the time of perforating. The cased-hole gamma ray log, which responds to formations’ natural radioactivities is similar to an openhole gamma ray log. Correlation of these two logs enables easy location of the collars with respect to down-hole zones. A short joint of pipe at or near the zone of interest is very helpful in accurate depth control.

Read more . . .Logging Operations

Tuesday, June 4, 2013

Natural Gas Sweetening - Glycol Dehydration

Production Facility
Produced natural gas contains water vapor. The gas is usually saturated under reservoir conditions of temperature and pressure. As it flows up the tubing, some of this water vapor may condense as "free water." The remainder will remain as water vapor. The process of removing water vapor from a gas stream is called "gas dehydration. The amount of water vapor contained in a gas stream can be expressed in terms of concentration, mg/m3 in metric units (in the U.S., the normal units are pounds of water vapor per million standard cubic feet of gas, lbs/MMSCF), or in terms of the "dew point" of the gas. The dew point is the temperature at which water will condense from the gas stream as it is cooled. The higher the concentration of water vapor in a given gas stream the higher its dew point. Thus, gas dehydration is also called "dew point depression," the lowering of the dew point of a gas by lowering the concentration of water vapor in the gas. Gas is dehydrated to prevent hydrate formation, to prevent corrosion, or to meet a sales gas contract. Hydrates are loosely-linked, crystal-like chemical compounds of hydrocarbon and water resembling dirty ice. If hydrates form, they can accumulate in valves and fittings, blocking or restricting gas flow. In order for hydrates to form, water must be present in liquid form, and the gas must be cooled to below its hydrate formation temperature, which is a function of gas composition and pressure. Thus, a gas stream which is dehydrated so that its dew point is lower than the temperature to which it will be cooled will have no water condensing from the gas, and hydrates will not form.

Water condensing in a gas line which is cooled below its dew point can cause corrosion, especially if the gas contains carbon dioxide (CO2) or hydrogen sulfide (H2S). Also, water in a gas line reduces the line capacity, increases the pressure drop in the line, and can produce undesirable or damaging slugging in the pipeline. For these reasons most gas sales contracts specify a maximum amount of allowable water vapor in the gas. For the Southern U.S. the limit is normally 112 mg/m3 (7 lbs/MMSCF), for the Northern U.S. 64 mg/m3 (4 lbs/MMSCF), and for Canada 32 to 64 mg/m3 (2 to 4 lbs/MMSCF). These limits are low enough to prevent water from dropping out in the line at normal transmission pressures and the lowest anticipated gas line temperature. These values correspond to dew points of approximately 0°C for 112 mg/m3 (32°F for 7 lbs/MMSCF), -7°C for 64 mg/m3 (20°F for 4 lbs/MMSCF) and -18°C for 32 mg/m3 (0°F for 2 lbs/MMSCF) in a 6900 kPa (1,000 psi) gas line.
Gas can be dehydrated by cooling and separating the condensed liquids, by using specially designed low temperature separation processes, by using solid desiccants, or by using liquid desiccants. Cooling the gas stream and removing the free water with a separator is the simplest method of dehydration. However, this method is limited by the hydrate formation temperature unless some other hydrate preventative method has been taken.

Read more . . .Natural Gas Sweetening - Glycol Dehydration

Monday, June 3, 2013

Separation of oil, water and gas.

Gathering Station
 When oil and water are mixed with some intensity and then allowed to settle, a layer of relatively clean free water will appear at the bottom. The growth of this water layer will follow a curve. After a period of time, ranging anywhere from three minutes to twenty minutes, the change in the water height will be negligible. The water fraction obtained from gravity settling is called "free water." It is common practice to separate the free water before attempting to individually treat the remaining oil and emulsion layers. Three-phase separators, sometimes called free-water knockouts, are used to separate and remove any free-water phase that may be present. Because the flow stream enters a three-phase separator either directly from a producing well, or from another separator operating at a higher pressure, the vessel must be designed to separate any gas that flashes from the liquid as well as the oil and water, hence the name three-phase. The basic design aspects of three-phase separators are identical to those of twophase separators. The only differences are that more space must be provided for oilwater settling and some means of removing the free water must be added. Threephase separators are designed as either horizontal or vertical pressure vessels.

The fluid enters the separator and hits an inlet diverter which produces a sudden change in the fluid's velocity and direction. The initial gross separation of liquid and vapor occurs at this point. The force of gravity causes the heavier liquid droplets to fall out of the gas stream to the bottom of the vessel, where the liquid is collected. This liquid collection section holds the liquid during the appropriate retention time required to let dissolved gas evolve out of the oil and rise to the vapor space. This section also provides a surge volume, if necessary, to handle intermittent slugs of liquid. The separated liquid then leaves the vessel through the liquid dump valve, which is regulated by a level controller. The level controller senses changes in liquid level and controls the dump valve accordingly. The separated gas flows over the inlet diverter and then horizontally through the gravity-settling section above the liquid. As the gas flows through this section, small drops of liquid that were entrained in the gas and not separated by the inlet diverter are separated out by gravity and fall to the gas-liquid interface. Some of the drops are of such small diameter that they are not easily separated in the gravity-settling section. However, before the gas leaves the vessel it passes through a coalescing section or mist eliminator. In this section, metal vanes, wire

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Sunday, June 2, 2013

Treatment and Handling of Separated Fluids (Oil, gas and water)

Vertical Separator
 After the gross separation of the produced fluid stream has taken place, further treating of the individual gas, oil, and water phases often must be carried out to meet the specifications of pipeline sales contracts. For example:
• natural gas cannot contain excessive amounts of CO2 or H2S;
• the gas must be delivered to a pipeline at a specified pressure;
• the gas must not contain water vapor,which can condense and form hydrates or can cause corrosion and added pressure losses (typical contracts call for less than 7 lb/MMscf or 112 kg/million m3);
• crude oil may not contain excessive amounts of sediment or emulsified water (BS&W) or salt dissolved in water (typically less than 1% BS&W and less than 10 lb salt per 1000 bbl or 28 kg salt per 1000 m3);
• produced water must be cleansed of dispersed oil before disposal
Compressors may be required to raise the pressure of the gas streams to pipeline pressure. Several stages of compression can be utilized to compress the individual low pressure and intermediate pressure gas streams. The two basic types of compressors used in production facilities are reciprocating and centrifugal compressors. Reciprocating compressors use a piston and cylinder arrangement with inlet (suction) and outlet (discharge) valves synchronized with the piston movement. Centrifugal compressors use finned wheels that rotate at high speed and cause an increase in gas velocity, which is then converted to increased pressure. Centrifugal compressors are normally operated by gas-fired turbines. Compressor installations must be designed with a certain degree of flexibility to handle the changes in gas volumes and pressures that occur over the life of a field. A type of separator known as a scrubber, or suction drum is typically found just upstream of a compressor, to prevent liquids from entering the compressor cylinders.

We can expect to find gas-sweetening equipment for the removal of hydrogen sulfide, if this contaminant is present. Such equipment normally relies on a chemical reaction between the "sour" gas and another compound (for example, iron oxide in the "iron sponge" method, or an amine solution) to selectively remove the corrosive and toxic compound.

Dehydration of the gas stream is typically accomplished in most oil processing facilities by using a liquid desiccant such as triethylene glycol to absorb water vapor as the gas stream is bubbled through the chemical solution. The "wet" glycol can then be heated to drive off the accumulated water and reused in the closed system. Other approaches to gas dehydration include:
• contacting the gas with a solid desiccant such as silica gel, or a molecular sieve. These units achieve very low moisture content levels but are relatively expensive and more common in gas processing plants than production facilities;
• cooling the gas by refrigeration or by expansion of the gas stream in a low temperature extraction (LTX) unit to condense the water. This can cause solid hydrocarbon-water compounds (hydrates) to form. These hydrates must be melted to keep them from plugging the system.

Looking at the separated oil stream we find our major problem to be the removal of emulsified water from the oil. Oil-treating vessels typically rely on settling-time, chemicals, heat, electricity, or a combination of these methods to break the film surrounding each water droplet and cause the droplets to coalesce and form larger drops, thus allowing the density difference to separate the two phases. Small amounts of emulsified water that contain large amounts of salt will require removal, as salt can foul refinery equipment. This may be accomplished by mixing the treated oil with fresh water and re-treating until the dissolved salt content of the entrained water is sufficiently low, a type of process that is common at the inlet to refineries and in certain parts of the Middle East.

In areas where large volumes of crude oil must be stored and transported, crude stabilization is sometimes used to adjust the vapor pressure of the oil and prevent loss of the more volatile components during transport. In a stabilizing process, fractionating columns may be used to reclaim condensate from separated gas. This condensate is then returned to the crude oil to increase the volume of liquid sold, and its API gravity (and therefore price).

Both the gas and oil streams must be metered before sale. Orifice meters, which measure pressure drop across an orifice and relate the drop to gas flow rate, are the most common type of gas measurement device in the oil field. Oil volumes are typically measured by gauging levels in storage tanks by positive displacement meters that segment the oil flow and keep an account of the discrete volumes, or by turbine meters. Lease automatic custody transfer (LACT) units are sometimes used to automatically measure oil volumes, monitor oil quality, and record a legal transfer of custody from seller to buyer.

The produced water stream that flows from three-phase separators and/or the oil treating vessels must undergo further treatment to remove droplets of oil that have escaped the earlier processes. Skim tanks allow the water to remain in one place long enough for coalescence of the oil droplets and gravity separation to occur. The inlet on such a vessel is designed to spread out the oily water and force the oil droplets to rise through the water in the vessel, where they coalesce and are skimmed off the surface. In plate coalescers, closely spaced parallel plates allow the oil droplets to rise a relatively short distance to a plate surface, where coalescence and capture occur. Precipitators, or filters, which employ a bed of coalescing medium such as wood shavings or hay, have been common in the past but are difficult to maintain. "SP" packs cause coalescence of the oil droplets in the water by forcing the water through a serpentine path so as to create turbulence, but without shearing the oil droplets and making them smaller. Gas flotation units utilize dissolved or dispersed gas in the water to contact the oil drop-lets and bring them to the surface in a froth. After the water has been treated to specification by using one or several of these methods, it may be metered and then disposed of overboard at offshore locations, injected into disposal or injection wells as water or steam, or even used to irrigate fields in some areas.

Read more . . .Treatment and Handling of Separated Fluids (Oil, gas and water)

Production Facilities

Well Testing Barge

The fluid produced from a well is usually a mixture of oil, gas, water, and sediment in varying amounts and at elevated temperatures and pressures. The oil alone is a complex mixture of many hydrocarbon compounds, including compounds which enter the gas phase during the production process. Gas may also be produced from the reservoir in varying amounts and travel up the tubing as bubbles entrained in the oil. Alternatively, oil droplets may be entrained as a mist in the gas. Formation water may be carried in the gas as water vapor, emulsified as droplets within the oil, or produced as free water containing dissolved gas, dissolved salts, and entrained oil. Sand and silt from the formation and rust or scale from the tubing or casing may also be included in the produced fluid stream, along with CO2, H2S, and other nonhydrocarbon contaminants. These elements may be present in a wide range of relative proportions, so it is easy to see the reason for the wide variety of production processing equipment used in our industry.
Surface production facilities must be designed to turn this mixture into separate streams of clean, dehydrated oil and gas, and safely disposable water and solids. The oil and gas must be metered and sold to a pipeline or delivered to a plant or refinery for further processing.
The system begins at the wellhead, which for flowing wells will usually include a choke to control the flow rate. The pressure drop across the choke is determined by the flowing tubing pressure (upstream) and the initial process vessel operating pressure (downstream) . Varying the choke size varies the flow rate. When two or more wells are commingled at a central processing facility, it is necessary to use a production manifold to combine the flow streams or to divert a single stream for testing or special treatment.

The first component of the processing facility the produced fluid encounters is typically some type of separator. Separators manipulate the stream of produced fluid to take advantage of the density differences that exist among gas, oil, and water and that cause these phases to separate. A two-phase separator separates gas and liquids; a three-phase separator goes one step further and separates oil and water as well. Separators come in a variety of configurations and operating pressures depending on the degree of gas-oil separation desired and the producing pressure of the Production stream. Stage separation, which typically involves high, intermediate and low pressure separators in series, can maximize oil volumes and allow several
wells with a variety of flowing tubing pressures to be serviced by the same facility. Because a separation vessel is normally the initial Processing vessel in any facility, improper design of this component can cause a bottleneck and reduce the capacity of the entire system.

Read more . . .Production Facilities

The History of Pertamina

PERTAMINA is a State Owned oil & gas company (National Oil Company), established on December 10, 1957 under the name PT PERMINA. In 1961 the company changed its name to PN PERMINA and after the merger with PN PERTAMIN in 1968 it became PN PERTAMINA. With the enactment of Law 8 of 1971 the company became PERTAMINA. This name persisted until after PERTAMINA changed its legal status to PT PERTAMINA (PERSERO) on October 9, 2003.

PERTAMINA's scope of business incorporates the upstream and downstream sectors. The upstream sector covers oil, gas and geothermal energy exploration and production both domestically and overseas. The foregoing is pursued through own operations and through partnerships in the form of joint operations with JOBs (Joint Operating Bodies), TACs (Technical Assistance Contracts) and JOCs (Joint Operating Contracts), whereas the downstream sector includes processing, marketing, trading and shipping. Commodities produced range from Fuel (BBM) and Non Fuel (Non BBM), LPG, LNG, petrochemicals to Lube Base oil.

With the enactment of the Law of the Republic of Indonesia No. 22 of 2001 on November 23, 2001 relating to Oil and Gas, Law No. 8 of 1971 relating to the State Oil and Gas Mining Company was declared void. In accordance with the provisions of Law No. 22 of 2001, PERTAMINA was transformed into a Public Liability Company (Persero) designated PT. PERTAMINA (PERSERO) under Government Regulation No. 31 of 2003. All existing PERTAMINA provisions including its structural organization, employment guidelines and procedures as well as other matters associated with its duties and responsibilities, unless such matters are in contravention of the said Government Regulation, are declared to continue in force until the Company provides otherwise.

PT PERTAMINA (PERSERO) was established under Notarial Deed of Lanny Janis Ishak, SH No. 20 of September 17, 2003, and ratified by the Minister for Law & Human Rights under Decision No. C-24026 HT.01.01 on October 9, 2003. The above proceeded in accordance with the provisions set forth in Law No. 1 of 1995 relating to Limited Liability Companies, Government Regulation No. 12 of 1998 relating to Public Companies (Persero), and Government Regulation No. 45 of 2001 relating to Amendment to Government Regulation No. 12 of 1998.

Consistent with its deed of establishment, the objective of the PERSERO is to engage in oil and gas exploitation, domestically and overseas, as well as in other exploitation associated with or supporting oil and gas operations.

Read more . . .The History of Pertamina

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