Deepwater Course Material

• Title : Centrilift 9 Steps ESP Design
• Publish : www.spdltd.com, A member of the Petrofac Group
• Type Document : pdf 
• Release : N/A
• Total Page : 20 Chapter
• Size : 31.19 Mb

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When drilling, it is vital that the actual pore pressure is predicted from the parameters observed.
Available kick tolerance should be constantly updated as the hole section progresses

• If kick tolerance is predicted to fall below the pre-defined acceptable value, consideration must be given to setting casing early 
• for wildcat exploration wells it is advisable to plan the well such that there is a contingency casing string available should this be required

Swabbing can induce an influx in a deepwater well due to

• small margins between pore pressure mud gradient and formation strength 
• high mud gel strength in the upper hole sections where mud temperature may be low 
• consider pumping out of the hole to reduce the risk of swabbing 
• Identify possible requirement to pump out in the drilling programme

When drilling into a potentially abnormally pressured formation in deepwater, it is good practice to make dummy connections or “pumps off tests”routinely

• gas levels at bottoms up must be monitored to check for increased levels of connection gas which could indicate that the hydrostatic static overbalance is close to pore pressure.

A very long riser system can mask gas peaks

• especially if the riser boost line is introducing a significant fraction of the total mud flow at the BOP
• masking effect of the riser is most apparent when drilling smallhole sizes at low flow rates 
• tracking of gas readings may be considerably more difficult in deepwater operations.

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Centrilift Steps ESP Design

• Title : Centrilift 9 Steps ESP Design
• Publish : Centrilift a Baker Hughes Company
• Type Document : pdf 
• Release : N/A
• Total Page : 33 Page
• Size : 7.76 Mb

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The Centrilift Training Center offers high quality education programs, both for centrilift assocoates who design , build and service and for our valued customers.
POur modern training facility includes full media equipped classroms, a shop training area and a media development center. in addition to a permanent staff of proffessional, experienced instructors, numerous memebrs of the centrilift organization are on call in their areas of experience.

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Conventional Surface Wellheads Draft

• Title : Conventional Surface Wellheads Draft by Cameron
• Publish : Western Hemisphere Cameron PO Box 1212 Houston Texas 77251-1212
• Type Document : pdf 
• Release : N/A
• Total Page : 25 Page
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Cameron Conventional Wellhead Systems provide the flexibility, compatibility and interchangeability required for a wide range of surface applications. With the proven features of Cameron systems comes reduced inventory requirements, lower costs and the ability to provide standard components.
Cameron provides two Conventional Wellhead Systems, the S Wellhead and IC Wellhead. The Cameron S Conventional Wellhead System offers the industry’s highest capacity conventional spool-type wellhead and is designed for use with all well depths and types of completions. The IC Wellhead is a costeffective, reliable system for a variety of applications. Although components are not interchangeable, the S Wellhead may be used in place of the IC Wellhead for all applications. In addition, both wellheads are compatible with most Cameron tubing spool and hanger configurations.
Cameron has earned a reputation for quality wellhead products
that meet or exceed API 6A specifications. Cameron offers a complete line of conventional wellheads and Christmas trees to suit all casing and tubing programs for working pressures up to 30,000 psi. Equipment for surface applications ranges from low pressure, conventional equipment to systems for severe service and geothermal applications. For equipment requirements not covered in this brochure, contact your Cameron representative. Selecting a Wellhead System The first step in determining which Cameron wellhead system is best for your application is to determine the casing hanger style to be used. Each hanger profile is unique and is generally compatible with only a limited number of casing head/spool bowls. Cameron has a complete line of slip-type casing hangers divided into two segments, SB and IC, each serving different applications.

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ESP Handbook

• Title : ESP Handbook
• Publish : N/A
• Type Document : pdf 
• Release : N/A
• Total Page : 67 Page
• Size : 7.78 Mb

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Seals contain a labyrinth chamber with a blacking fluid between the well fluid and motor ail. The blocking fluid is commonly the same ail used In the motor. It may also be a high density fluid for special applications. Seals may also contain a positive elastomeric barrier, or BAG. In combination with a labyrinth chamber. Several operators have Increased run lives using tandem seal sections as an added means of protection.

Gas Separators (optional)

Gas reduces the efficiency of ESPs; therefore. gas separators may be Installed between the seal and pump to reduce the amount of tree gas entering the pump. Both reverse flow and rotary separators are available with the latter being more efficient at gas separation. Some operators run tandem gas separators In high GaR wells 10 more effectively remove gas trom the pump intake. Gas separators handle significant volumes of free gas efficiently.

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Drilling Well Completion

• Title : Drilling Well Completion by Carl Gatlin Departmen of Petroleum The Universuty of Texas
• Publish : Prentice Hall, Inc Englewood Cliffs, NJ
• Type Document : pdf 
• Release : December 2006
• Total Page : 348 Page
• Size : 33.47 Mb

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None

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Drilling Practices Manual

• Title : Drilling Practices Manual by Preston L. Moore
• Publish : Peen Well Book Tulsa. Oklahoma USA
• Type Document : pdf 
• Release : December 1986
• Total Page : 604 Page
• Size : 24.75 Mb

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DEPTH LIMITATION
After the requirements mentioned above are determined, establish your own minimum standards for the rig, commonly referred to as "depth rating." Unfortunately, there is no real standard for depth rating, so much of the term's meaning is lost. This necessitates an analysis by the planner to establish rating standards for the case at hand. Table 1-1 shows criteria for determining depth limitation.

Derrick and Mast
Derrick or mast ratings are made from the maximum hookload capacity. Know under what conditions these ratings were made when comparing them. For instance, a rating may be valid only with a certain type of crownI traveling-block line configuration. In addition, double check the credibility of the rating if it is attached to a non-namebrand mast. If there is some doubt, an API-certified inspector should verify all ratings. Other factors to consider with mast rating are leg loading, substructure rating, and maximum wind loading with drillpipe in the derrick.
In the context of rig selection, mast rating figures are needed to determine if the rig will be adequate under the maximum loading condition anticipated during drilling. This condition typically occurs while running the heaviest string of casing, so calculation of the maximum string weight is the first step in analyzing mast load. To illustrate what occurs during mast loading, consider first the simplest of cases, demonstrated in Fig. 1-1. In this case, a 100-1b load is being lifted with a pulley. Total load on the derrick is 200 lb because the two lines are each exerting a downward force of 100 lb. Fig. 1-2 shows the
familiar block and tackle system employed to lift the same 100 lb.

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Well Performance Manual

• Title : Well Performance Manual by Hemanta Mukherjee
• Publish : Schlumberger Educational Services 300 Schlumberger Drive SugarLand, Texas 77478
• Type Document : pdf 
• Release : June 1991
• Total Page : 171 Page
• Size : 4.89 Mb

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A well can be defined as an interphasing conduit between the oil and gas reservoir and the surface needed to produce reservoir fluid handling facility. This interface is ble asset. The physical descripto the surface, making it a tangi- For optimal production, a well tion of a well is quite involved. engineering considerations. The design requires some complex optimal production refers to a maximum return on investment. The physical description of a typical oil or gas well is shown in Fig. 1.1.

In the performance of a well the Fig. 1 .I Possible pressure losses in the producing system drainage volume of the reservoir for aflowing well. draining to the well plays an important role. A well a br gas production scyostmembin. Aed p wroitdhu tchtieo rne ssyersvteomir disr a tihnuinscg o imntpoo iste dis onfo trhme afldlylo cwalilnegd mana jooirl components - 

• porous medium
• completion (stimulation, perforations, and gravel pack)
• vertical conduit with safety valves and chokes
• artificial lift system such as pumps, gas lift valves, etc
• horizontal flowlines with chokes, and other piping components e.g. valves, elbows, etc.

In an oil or gas production system, the fluids flow from the drainage in the reservoir to the separator at the surface. The average pressure within the drainage boundary is often production system and is assumed to remain constant over a fixed time interval during alled the average reservoir pressure. This pressure controls the flow through a depletion. When this pressure changes, the well's performance changes and thus the well needs to be re-evaluated. The average reservoir pressure changes because of normal reservoir depletion or artificial pressure maintenance with water, gas, or other chemical injection.
The separator pressure at the surface is designed to optimize production and to retain lighter hydrocarbon components in the liquid phase. This pressure is maintained by using mechanical devices such as pressure regulators. As the well produces or injects, there is a a continuous pressure gradient from the reservoir to the separator.

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Well Control Training Manual

• Title : Aberdeen Drilling School - Well Control Training Manua
• Publish : Aberdeen Drilling School
• Type Document : pdf 
• Release : March 2002
• Total Page : 390 Page
• Size : 7.40 Mb

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None

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Well Cementing

• Title : Well Cementing [ pdf ] by Erik B. Nelson
• Publish : Schlumberger Educational Services 300 Schlumberger Drive SugarLand, Texas 77478
• Type Document : pdf 
• Release : December 1990
• Total Page : 487 Page
• Size : 40.15 Mb

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Testing Equipment

One of the most outstanding developments of mechanical testing devices for cement slurry design was the hightemperature, high-pressure thickening time tester developed in 1939 by R. F. Farris (retired, Amoco Production Company) (Smith, 1987). This device allowed a more accurate determination of the thickening time of cement slurries under a simulated downhole environment of
temperature and pressure. This device continues to be the standard for the industry 50 years later, and is part of the API Specification 10 for well cements.

Flow After Cementing
Perhaps the most important development for deeper high-pressure gas wells has been the control of flow after cementing. Without proper slurry design, natural gas can invade and flow through the cement matrix during the WOC time. This gas must be prevented from invading the cement. Failure to prevent gas migration can cause such problems as high annular pressures at the surface, blowouts, poor zonal isolation, loss of gas to nonproductive zones, poor stimuation, low producing rates, etc. All of these are costly to correct. It is generally acknowledged in the industry that the mechanism that allows gas invasion into the cement matrix is the gel-strength development
of the slurry as it changes from a liquid to a solid. In this condition, the cement loses its ability to transmit hydrostatic pressure, and gas invasion may occur. Other mechanisms include excessive fluid loss, bridging, and
the formation of microannuli. There are several successful methods (Cheung and Beirute, 1985; Garcia and Clark, 1976; Webster and Eikerts, 1979; Bannister et al., 1983; Tinsley et al.; 1980; Griffin et al., 1979) to control gas migration as shown in Fig. 4, each with its advantages. Usually a combination of methods works best. In selecting optimum methods for controlling gas migration, many well conditions must be considered: formation pressure, permeability, gas flow rate, bottomhole temperature; wellbore geometry, well deviation, height of the cement column, and formation fracture pressure.

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Main Part Centrifugal Pump

• Title : Main Part Centrifugal Pump [ pdf ] by Igor J Karassik and CC Heald
• Publish : N/A
• Type Document : pdf 
• Release : N/A
• Total Page : 86 Page
• Size : 1.39 Mb

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CLASSIFICATION AND NOMENCLATURE
A centrifugal pump consists of a set of rotating vanes enclosed within a housing or casing that is used to impart energy to a fluid through centrifugal force. Thus, stripped of all refinements, a centrifugal pump has two main parts: (1) a rotating element, including an impeller and a shaft, and (2) a stationary element made up of a casing, casing cover, and bearings. In a centrifugal pump, the liquid is forced by atmospheric or other pressure into a set  of rotating vanes. These vanes constitute an impeller that discharges the liquid at its periphery at a higher velocity. This velocity is converted to pressure energy by means of a volute (see Figure 1) or by a set of stationary diffusion vanes (see Figure 2) surrounding the impeller periphery. Pumps with volute casings are generally called volute pumps, while those with diffusion vanes are called diffuser pumps. Diffuser pumps were once quite commonly called turbine pumps, but this term has become more selectively applied to the vertical deep-well centrifugal diffuser pumps usually referred to as vertical turbine pumps. Figure 1 shows the path of the liquid passing through an end-suction volute pump operating at rated capacity (the capacity at which best efficiency is obtained). Impellers are classified according to the major direction of flow in reference to the axis of rotation. Thus, centrifugal pumps may have the following:

• Radial-flow impellers (see Figures 25, 34, 35, 36, and 37)
• Axial-flow impellers (see Figure 29)
• Mixed-flow impellers, which combine radial- and axial-flow principles (see Figures 27 and 28)

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Jet Pump 2

• Title : Jet Pump 1 [ pdf ] by Alex M Jumpeter
• Publish : N/A
• Type Document : pdf 
• Release : N/A
• Total Page : 27 Page
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This section contains extensive design and application experience for a variety of jet pump configurations. Although this section concentrates on eductors (termed LJL jet pumps in Section 4.1), experience with other motive (primary) and secondary fluids is also included. The theoretical developments of Section 4.1 are the basis for what is presented here, the dimensional design ratios being generally within the ranges mentioned therein. Therefore, the only theory in this section is the empiricism that is utilized in the examples and applications presented. Refer to Section 4.1 for further explanation.

....
This equation is used to calculate the motive quantity or pressure from the operating parameters. This nozzle and diffuser diameters are calculated from the equation Q wAV, using suitable nozzle and diffuser entrance coefficients. The principal problems in design concern the size and proportions of the mixing chamber, the distance between nozzle and diffuser, and the length of the diffuser. Eductor designs are based on theory and empirical constants for length and shape. The most efficient units are developed from calculated designs that are then further modified by prototype testing. Figure 2 shows this factor plotted against NPSH (net positive suction head) for a single-nozzle and annular-nozzle eductor. In an annular-nozzle eductor, the motive fluid is introduced around the periphery of the suction fluid, either by a ring of nozzles (Figure 15) or by an annulus created between the inner wall of the diffuser and the outer wall of the suction nozzle (Figure 14). The NPSH is the head available at the centerline of the eductor to move and accelerate suction fluid entering the eductor mixing chamber. NPSH is the total head in feet (meters) of fluid flowing and is defined as atmospheric pressure minus suction pressure minus vapor pressure of suction or motive fluid, whichever is higher. Increased viscosity of motive or suction fluid increases the frictional and momentum losses and therefore reduces the efficiency factor of Figure 2. Below 20 cP, the effect is minimal (approximately 5% lowering of e). Above this value, the loss of performance is more noticeable and empirical data or pilot testing is used to determine sizing parameters.

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Jet Pump 1

• Title : Jet Pump 1 by Richard G Cunningham
• Publish : N/A
• Type Document : pdf 
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• Total Page : 20 Page
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INTRODUCTION
The jet pump transfers energy from a liquid or gas primary fluid to a secondary fluid. The latter may be a liquid, a gas, a two-phase gas-in-liquid mixture, or solid particles transported in a gas or a liquid. Examples of all these combinations have been reported in the technical literature. Reference 1, the major bibliography in this field, contains over 400 abstracts. Although the terms “ejector” and “eductor” are also applied, the term “jet pump” will be used here. The jet pump offers significant advantages over mechanical pumps: no moving parts for improved reliability, adaptability to installation in remote or hazardous environments, simplicity, and low cost. The primary drawback is efficiency: both frictional losses and unavoidable mixing losses are incurred. Nevertheless, careful design can produce pumps with efficiencies on the order of 30—40%. The jet pump in Figure 1 is typical of liquid-jet pumps and low Mach-number gas-jet/gas pumps. Compressible-flow pumps, for example, steam-jet ejectors, employ converging-diverging nozzles for full expansion of the jet.

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Centrifugal Pump

• Title : Centrifugal Pump by Paul Cooper
• Publish : N/A
• Type Document : pdf 
• Release : N/A
• Total Page : 95 Page
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INTRODUCTION
A centrifugal pump is a rotating machine in which flow and pressure are generated dynamically. The inlet is not walled off from the outlet as is the case with positive displacement pumps, whether they are reciprocating or rotary in configuration. Rather, a centrifugal pump delivers useful energy to the fluid or “pumpage” largely through velocity changes that occur as this fluid flows through the impeller and the associated fixed passageways of the pump; that is, it is a “rotodynamic” pump. All impeller pumps are rotodynamic, including those with radial-flow, mixed-flow, and axial-flow impellers: the term “centrifugal pump” tends to encompass all rotodynamic pumps.
Although the actual flow patterns within a centrifugal pump are three-dimensional and unsteady in varying degrees, it is fairly easy, on a one-dimensional, steady-flow basis, to make the connection between the basic energy transfer and performance relationships and the geometry or what is commonly termed the “hydraulic design” (more properly the “fluid dynamical design”) of impellers and stators or stationary passageways of these machines. In fact, disciplined one-dimensional thinking and analysis enables one to deduce pump operational characteristics (for example, power and head versus flow rate) at both the optimum or design conditions and off-design conditions. This enables the designer and the user to judge whether a pump and the fluid system in which it is installed will operate smoothly or with instabilities. The user should then be able to understand the offerings of a pump manufacturer, and the designer should be able to provide a machine that optimally fits the user’s requirements.

The complexities of the flow in a centrifugal pump command attention when the energy level or power input for a given size becomes relatively large. Fluid phenomena such as recirculation, cavitation, and pressure pulsations become important; “hydraulic” and mechanical interactions—involving stress, vibration, rotor dynamics, and the associated design approaches, as well as the materials used—become critical; and operational limits must be understood and respected.

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Proses Industrial Instrument & Control

• Title : Proses Industrial Instrument & Control Handbook [ pdf ] by Gregory K. McMillan and Douglas M. Considine
• Publish : McGRAW-HILL
• Type Document : pdf 
• Release : December 1999
• Total Page : 11 Chapter
• Size : 11.30 Mb

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General Categories of Control Valves
Control valve here means any power-operated valve, whether used for throttling or on–off control. Varieties from which to select, as listed in Table 1, include sliding stem valves and rotary valves. Typical sliding-stem valves are straight-pattern valves (sometimes called globe valves) and anglepattern valves. Rotary valves include ball and butterfly valves. Other varieties such as motorized gate valves, louvers, pinch valves, plug valves, and self-operated regulators are not considered here. These major types, sliding-stem and rotary, are further divided into ten subcategories according to relative performance and cost. Despite variations found within each category—such as cage guiding and stem buiding—all valves within a given subcategory can be considered very much alike in the early stages of the valve selection process. Selecting a valve involves narrowing your selection to one of these subcategories and then comparing specific valves in that group (Table 2).

Designations NPS and DN are used in Table 1 and throughout this section. NPS is a designation for nominal pipe size. It comprises the letters NPS followed by a dimensionless number, which is indirectly related to the physical size, in inches, of the end connections. DN is an international designation for nominal diameter. It comprises the letters DN followed by a dimensionless whole number, which is indirectly related to the physical size, in millimeters, of the end connections.
 

Sliding-Stem Valves
The most versatile of the control valves are the sliding-stem valves. Straight-pattern, angle-pattern, and three-way valves can be purchased in sizes ranging from NPS 1/2 to NPS 20 or from DN 15.

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Handbook of Natural Gas

• Title : Handbook of Natural Gas Transmission And Processing by Saeid Mokhatab William A.Poe James G Speight
• Publish : Gulf Professional Publishing is an imprint of Elsevier
• Type Document : pdf
• Release : December 2006
• Total Page : 672 Page
• Size : 8.36 Mb

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GAS SOURCES
Natural gas produced from geological formations comes in a wide array of compositions. The varieties of gas compositions can be broadly categorized into three distinct groups: (1) nonassociated gas that occurs in conventional gas fields, (2) associated gas that occurs in conventional oil fields, and (3) continuous (or unconventional) gas. Some types of unconventional gas resources include “tight gas” or “tight sands gas,” which is found in low-permeability rock; “coalbed methane (CBM),” which is natural gas that has been formed along with the geological processes that formed coal; “natural gas from geopressurized aquifers,” which refers to gas dissolved under high pressure and at high temperatures in brines located deep beneath the Earth’s surface; “gas hydrates,” which are ice-like structures of water and gas located under the permafrost; and “deep gas,” which is found at levels much deeper than conventional gas.
Although there is no scientific consensus, some believe deep gas originated from inorganic sources and that it exists everywhere as a result of the geological processes that formed the earth. Of the unconventional gas sources, the one most important to the gas transportation industry is coal bed methane.

1.4.1 Non-associated Gas
Nonassociated gas (sometimes called “gas well gas”) is produced from geological formations that typically do not contain much, if any, higher boiling hydrocarbons (gas liquids) than methane. Nonassociated gas can contain nonhydrocarbon gases such as carbon dioxide and hydrogen sulfide. Nonassociated gas is directly controllable by the producer; one just turns the valves. The gas flows up the well under its own energy, through the wellhead control valves, and along the flow line to the treatment plant. Treatment requires the temperature of the gas to be reduced to a point dependent upon the pressure in the pipeline so that all liquids that would exist at pipeline temperature and pressure condense and are removed.

1.4.2 Associated Gas
Associated gas is produced during crude oil production and is the gas that is associated with crude oil. Crude oil cannot be produced without producing some of its associated gas, which comes out of solution as the pressure is reduced on the way to and on the surface. Properly designed crude oil well completions and good reservoir management are used to minimize the production of associated gas so as to retain the maximum energy in the reservoir and thus increase ultimate crude oil recovery. Crude oil in the reservoir with minimal or no dissolved associated gas is rare and as dead crude oil is often difficult to produce as there is little energy to drive it.
After the production fluids are brought to the surface, they are separated at a tank battery at or near the production lease into a hydrocarbon liquid stream (crude oil or gas condensate), a produced water stream (brine or salty water), and a gaseous stream. The gaseous stream is traditionally very rich (rich gas) in natural gas liquids (NGLs). Natural gas liquids include ethane, propane, butanes, and pentanes and higher molecular weight hydrocarbons (C+6 ). The higher molecular weight hydrocarbons product is commonly referred to as natural gasoline.

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Piping Codes and Standards

• Title : Piping Codes and Standards by Mohinder L. Nayyar, P.E
• Publish : Mohinder L. Nayyar, P.E. ASME Fellow
• Type Document : pdf 
• Release : N/A
• Total Page : 63 Page
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Codes usually set forth requirements for design, materials, fabrication, erection, test, and inspection of piping systems, whereas standards contain design and construction rules and requirements for individual piping components such as elbows, tees, returns, flanges, valves, and other in-line items. Compliance to code is generally mandated by regulations imposed by regulatory and enforcement agencies. At times, the insurance carrier for the facility leaves hardly any choice for the owner but to comply with the requirements of a code or codes to ensure safety of the workers and the general public. Compliance to standards is normally required by the rules of the applicable code or the purchaser’s specification.
Each code has limits on its jurisdiction, which are precisely defined in the code. Similarly, the scope of application for each standard is defined in the standard. Therefore, users must become familiar with limits of application of a code or standard before invoking their requirements in design and construction documents of a piping system.
The codes and standards which relate to piping systems and piping components are published by various organizations. These organizations have committees made up of representatives from industry associations, manufacturers, professional groups, users, government agencies, insurance companies, and other interest groups.
The committees are responsible for maintaining, updating, and revising the codes and standards in view of technological developments, research, experience feedback, problems, and changes in referenced codes, standards, specifications, and regulations.
The revisions to various codes and standards are published periodically. Therefore, it is important that engineers, designers, and other professional and technical personnel stay informed with the latest editions, addenda, or revisions of the codes and standards affecting their work.
While designing a piping system in accordance with a code or a standard, the designer must comply with the most restrictive requirements which apply to any of the piping elements.
In regard to applicability of a particular edition, issue, addendum, or revision of a code or standard, one must be aware of the national, state, provincial, and local laws and regulations governing its applicability in addition to the commitments made by the owner and the limitations delineated in the code or standard.

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Workover Well Control Manual

• Title : Workover Well Control Manual by Chevron Petroleum Technology Company Drilling Technology Center
• Publish : Chevron Petroleum Technology Company
• Type Document : pdf 
• Release : December 1994
• Total Page : 298 Page
• Size : 2.31 Mb

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INTRODUCTION AND RESPONSIBILITIES 

INTRODUCTION
The primary goal of every completion and workover operation is to complete the task in a safe and efficient manner without detrimental effects to the environment. This goal can only be accomplished if control of the well is maintained at all times. In order to comprehend Completion/Workover Well Control, we must first understand a few basic terms:

• Well Completion
• Well Workover
• Kick
• Blowout

1.1 Well Completion
This operation is performed at the completion of drilling operations to establish initial production from or injection into a well. There are many different types of completions utilized around the world. Examples include: open hole, cased hole perforated, single string, dual string, and gravel packed completions. Completion procedures will vary depending on the completion type and the area. In some areas, flowing wells can simply be perforated and put on production. In other areas, the wells may require stimulation treatments such as acid or frac jobs to produce at economic rates. Sometimes wells are completed in multiple zones in order to establish commercial production. Wells in low pressure areas often require an artificial lift mechanism (rod or submersible pump, gas lift valves, etc.) to produce at economic rates.

1.2 Well Workover
This operation is performed after the initial completion to either reestablish commercial production or injection, repair a mechanical problem in the well, or plug and abandon the well. Workover operations are usually initiated when hydrocarbon production rates decline substantially. Completions and workover operations are alike in that they vary depending on the type of well and the area. They can be as simple as changing out pumps in a rod job, or as complex as a multiple zone recompletion with a three or four-stage stimulation treatment. Sometimes workovers are done to control excessive water or gas production. Undesired water or gas production could be the result of a poor primary cement job or water/gas coning. These types of workovers typically involve a remedial cement job to control the unwanted water/gas production. Another common cause for remedial work is mechanical (tubing/casing) failures. These failures are often the result of erosion or corrosion occurring in the wellbore.

1.3 Kick
A kick is an influx, or flow, of formation fluids into the well. The successful detection and handling of kicks is extremely important

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Wild Well Control Tech Data Book

• Title : Wild Well Control Technical Data Book
• Publish : Wild Well Control Inc, 22730 Gosling Road Spring, Texas 77389 USA
• Type Document : pdf 
• Release : December 1994
• Total Page : 57 Chapter
• Size : 1.01 Mb

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None

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FMC Wellhead Manual

• Title : FMC Wellhead Manual
• Publish : FMC WellHead
• Type Document : pdf 
• Release : December 1994
• Total Page : 5 Chapter
• Size : 0.81 Mb

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Casing Heads
General Installation Guidelines
Leveling
The casing head must be installed so that the top flange is level, except in cases where the surface casing is not exactly vertical. In this case, the top flange face must be perpendicular to the casing string. Otherwise, there will be problems passing the drill bit through the head and running and landing subsequent casing strings.

Orientation
The casing head should establish the proper orientation for the remaining casing spools and completion equipment. Be sure the side outlets are orientated so that there is ample room to install the valve-removal (VR) lubricator.

Welding
Welding should only be performed by a qualified welder hired by the customer. You should make sure the weld area is thoroughly cleaned before welding. After welding and cool-down, conduct the hydrostatic test using clear water or other suitable fluid as specified by FMC engineering department. Test the weld to 80% of the casing collapse rating.

NOTE: Due to the variety of materials requested for use worldwide, exact weld procedures will not be supplied in this manual. A qualified welder of the customers choice should be utilized to weld on casing heads. FMC Engineering Department may be consulted for guidelines. Final procedures and responsibility for the weld rest with the customer's welder.

Before Installation

NOTE: Make sure all required personal protective equipment is obtained and used during this operation.
NOTE: A checklist is provided at the end of this section to further assist in the installation of this product.

• Check orientation of mud valve outlet to see that it will match up to flowlines. 
• See that there is enough clearance at the site and orient the head so that the VR lubricator may be attached for valve removal and reinstallation. 
• Determine the casing cut-off height so as to properly locate the top flange of the head. 
• Clean grease away from the area of the weld.

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Expro Slickline Training Manual

• Title : Expro Slickline Training Manual [ pdf ] by The Expro Group European Training Centre Forties Road, Montrose
  DD10 9 ET Scotland UK
• Publish : RGit Montrose
• Type Document : pdf 
• Release : December 1994
• Total Page : 352 Page
• Size : 27.07 Mb

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Decrypted Contents

WELL CONTROL AND BOP PUMPS

SINGLE WELL CONTROL PANEL
When conducting well servicing operations in a well, it is a necessary safety precaution to lock out any pneumatically or hydraulically activated valves and isolate them from the platform control system.
This has meant the introduction of a mobile well control panel which effectively duplicates the platform failsafe control system functionally for an individual well, but it is operated manually. The well control panel is also provided with an emergency shutdown system, enabling the UMV and DHSV to be closed instantly in an emergency situation.
An overview of the panel is given in Figure 10.1. It consists essentially of a control panel section comprising of two reservoirs which feed three pneumatically operated Haskel pumps. These provide a high pressure hydraulic supply for three functions:

• UMV control - direct hydraulic (fluid depending on location)
• DHSV control - direct hydraulic (fluid depending on location)
• Wireline BOP stuffing box control- direct hydraulic (hydraulic oil).

A separate hand pump system is incorporate to enable the operation of a hydraulic stuffing box system test line. An additional facility is provided to allow the hook-up of an independent inhibitor supply using the spare hose and reel.
The hydraulic supply hoses are wound onto four reels mounted beneath the control panel section. The low air supply/hydraulic pressure warning system is incorporated into the panel.
The warning system monitors DHSV pressure, UMV pressure and the air supply
pressure. If any of the aforementioned pressures fall below a pre-set level, an air hom sounds to warn the operator, air supply should be taken from plant air not rig air as this can be lost at times, such as water injection shut-down.

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