Petroleum & Gas Field Processing 06

• Title : Petroleum & Gas Field Processing 06 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
• Release : December 2003
• Total Page : 15 page
• Size : 0.31 Mb

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Desalting of Crude Oil

INTRODUCTION
The removal of salt from crude oil for refinery feed stocks has been and still is a mandatory step. This is particularly true if the salt content exceeds 20 PTB (pounds of salt, expressed as equivalent sodium chloride, per thousand barrels of oil).
The most economical place for the desalting process is usually in the refinery. However, when marketing or pipeline requirements are imposed, field plants are needed for processing the salty oil prior to shipping. The principles involved are the same whether desalting takes place at the refinery or in the field. Salt in crude oil is, in most cases, found dissolved in the remnant brine within the oil.
The remnant brine is that part of the salty water that cannot be further reduced by any of the dehydration methods described in the previous chapter. It is commonly reported as basic sediments and water (B.S.&W.). It is understood that this remnant water exists in the crude oil as a dispersion of very fine droplets highly emulsified in the bulk of oil. The mineral salts of this brine consist mainly of chlorides of sodium, calcium and magnesium. A summary of the properties of crude oil as received at the refinery is given in Table 1. Nelson [1] compiled the data given in Table 2 on the amount of salts found in oils for various regions in the world.
The amount of salt in the crude oil is a function of the amount of the brine that remains in the oil WR (% B.S.&W.) and of its salinity SR in parts per million (ppm). In other words, this relationship could be written in the following functional form (after Manning and Thompson [2]

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Petroleum & Gas Field Processing 05

• Title : Petroleum & Gas Field Processing 05 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
• Release : December 2003
• Total Page : 37 page
• Size : 0.89 Mb

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Emulsion Treatment and Dehydration of Crude Oil

INTRODUCTION
The fluid produced at the wellhead consists usually of gas, oil, free water, and emulsified water (water–oil emulsion). Before oil treatment begins, we must first remove the gas and free water from the well stream. This is essential in order to reduce the size of the oil–treating equipment. 

As presented in Chapters 3 and 4, the gas and most of the free water in the well stream are removed using separators. Gas, which leaves the separator, is known as ‘‘primary gas.’’ Additional gas will be liberated during the oil treatment processes because of the reduction in pressure and the application of heat. Again, this gas, which is known as ‘‘secondary gas,’’ has to be removed. The free water removed in separators is limited normally to water droplets of 500 mm and larger. Therefore, the oil stream leaving the separator would normally contain free water droplets that are 500 mm and smaller in addition to water emulsified in the oil. This oil has yet to go through various treatment processes (dehydration, desalting, and stabilization) before it can be sent to refineries or shipping facilities.
This chapter deals with the dehydration stage of treatment. The objective of this treatment is first to remove free water and then break the oil emulsions to reduce the remaining emulsified water in the oil. Depending on the original water content of the oil as well as its salinity and the process of dehydration used, oil-field treatment can produce oil with a remnant water content of between 0.2 and 0.5 of 1%. The remnant water is normally called the bottom sediments and water (B.S.&W.). The treatment process and facilities should be carefully selected and designed to meet the contract requirement for B.S.&W. Care should be taken not to exceed the target oil dryness. Removal of more remnant water than allowed by contract costs

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Petroleum & Gas Field Processing 04

• Title : Petroleum & Gas Field Processing 04 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
• Release : December 2003
• Total Page : 25 page
• Size : 0.35 Mb

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Three-Phase Oil–Water–Gas Separation

INTRODUCTION
The concepts, theory, and sizing equations for two-phase gas–liquid separators have been discussed in Chapter 3. The material presented in Chapter 3 applies, in general, to the separation of any gas–liquid system such as gas–oil, gas–water, and gas–condensate systems. In almost all production operations, however, the produced fluid stream consists of three phases: oil, water, and gas.
Generally, water produced with the oil exists partly as free water and partly as water-in-oil emulsion. In some cases, however, when the water– oil ratio is very high, oil-in-water rather than water-in-oil emulsion will form. Free water produced with the oil is defined as the water that will settle and separate from the oil by gravity. To separate the emulsified water, however, heat treatment, chemical treatment, electrostatic treatment, or a combination of these treatments would be necessary in addition to gravity settling. This is discussed in Chapter 5. Therefore, it is advantageous to first separate the free water from the oil to minimize the treatment costs of the emulsion.
Along with the water and oil, gas will always be present and, therefore, must be separated from the liquid. The volume of gas depends largely on the producing and separation conditions. When the volume of gas is relatively small compared to the volume of liquid, the method used to separate free water, oil and gas is called a free-water knockout. In such a case, the separation of the water from oil will govern the design of the vessel. When there is a large volume of gas to be separated from the liquid (oil and water), the vessel is called a three-phase separator and either the gas capacity requirements or the water–oil separation constraints may govern the vessel design. Free-water knockout and three-phase separators

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Petroleum & Gas Field Processing 03

• Title : Petroleum & Gas Field Processing 03 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
•  Release : December 2003
• Total Page : 56 page
• Size : 0.86 Mb

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Two-Phase Gas–Oil Separation

INTRODUCTION
At the high pressure existing at the bottom of the producing well, crude oil contains great quantities of dissolved gases. When crude oil is brought to the surface, it is at a much lower pressure. Consequently, the gases that were dissolved in it at the higher pressure tend to come out from the liquid. Some means must be provided to separate the gas from oil without losing too much oil.
In general, well effluents flowing from producing wells come out in two phases: vapor and liquid under a relatively high pressure. The fluid emerges as a mixture of crude oil and gas that is partly free and partly in solution. Fluid pressure should be lowered and its velocity should be reduced in order to separate the oil and obtain it in a stable form. This is  usually done by admitting the well fluid into a gas–oil separator plant (GOSP) through which the pressure of the gas–oil mixture is successively reduced to atmospheric pressure in a few stages.
Upon decreasing the pressure in the GOSP, some of the lighter and more valuable hydrocarbon components that belong to oil will be unavoidably lost along with the gas into the vapor phase. This puts the gas–oil separation step as the initial one in the series of field treatment operations of crude oil. Here, the primary objective is to allow most of the gas to free itself from these valuable hydrocarbons, hence increasing the recovery of crude oil.
Crude oil as produced at the wellhead varies considerably from field to field due not only to its physical characteristics (as explained in Chapter 2) but also to the amount of gas and salt water it contains. In some fields, no salt water will flow into the well from the reservoir along with the produced oil. This is the case we are considering in this chapter, where it is only necessary to separate the gas from the oil; (i.e., two-phase separation).

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Petroleum & Gas Field Processing 02

• Title : Petroleum & Gas Field Processing 02 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
•  Release : December 2003
• Total Page : 12 page
• Size : 0.37 Mb

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Composition and Characteristics of
Crude Petroleum
A Brief Review

GENERAL
Crude oils are complex mixtures of a vast number of hydrocarbon compounds. Properties of crude petroleum vary appreciably and depend mainly on the origin. In this chapter, the chemical composition of the crude oils is viewed, including the hydrocarbon series as well as the nonhydrocarbon compounds. Physical methods generally used for indentifying types of crude oils are described next. Characterization and classification of crude oils based on correlation indexes and crude assays are presented, followed by a comparison between some of the well-known types of oil.

CRUDE OIL COMPOSITION
The raw material that we deal with—referred to as crude petroleum—is, by definition, the naturally occurring rock oil produced as was explained in Chapter 1. In general, composition of crude oil may be studied by two methods:

1. Chemical approach
2. Physical methods
 

Chemical composition describes and identifies the individual chemical compounds isolated from crude oils over the years. Physical representation, on the other hand, involves considering the crude oil and its products as mixtures of hydrocarbons and describing physical laboratory tests or methods for characterizing their quality.

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Petroleum & Gas Field Processing 01

• Title : Petroleum & Gas Field Processing 01 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
• Release : December 2003
• Total Page : 42 page
• Size : 0.76 Mb

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Oil and Gas
From Formation to Production

INTRODUCTORY REMARKS
This book deals with the field surface operations and facilities for handling and processing the produced oil, gas, and water. This is an important aspect in the overall planning and development of the field and must be considered and integrated into the early stages of planning, economic evaluation, and development of the field. Before considering the surface production operations and facilities, however, extensive work and studies are first made to characterize and evaluate the reservoir, determine the production strategy for the life of the field, design the well completions that are compatible with the production strategy, and design the welldrilling programs.
Petroleum engineering students would, normally, have covered the subject matters related to the reservoir, well completion, drilling, and subsurface production methods before taking a course on surface production operations. Non-petroleum-engineering students taking this course, however, would be lacking such important and useful knowledge and background. This chapter, therefore, provides brief background information for the non-petroleum-engineering students to appreciate all operations related to the production of oil and gas.
A brief description of how oil and gas were formed and accumulated underground is first presented. A description of the various type of petroleum reservoir according to their geologic and production classifications is then provided. The exploration activities used in finding (discovering) petroleum reservoirs are then highlighted. Finally, an overview of the field development work, including the reservoir, drilling, and production engineering aspects of the development, are summarized.

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Petroleum & Gas Field Processing 00

• Title : Petroleum & Gas Field Processing 00 by H.K. Abdel-Aal and Mohamed Aggour - King Fahd University of Petroleum & Minerals Dhahran, Saudi Arabia, M.A Fahim Kuwait University Safat, Kuwait
• Publish : Marceld Ekkeirn, C New York Basel
• Type Document : pdf
• Release : December 2003
• Total Page : 14 page
• Size : 0.55 Mb

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Introduction
Fluids produced from oil and gas wells genrerally constitute mixtures of crude oil, natural gas, and salt water. These mixtures are very difficult to handle, meter, or transport. In addition to the difficulty, it is also unsafe and uneconomical to ship or to transport these mixtures to refineries and gas plants for processing. Further, hydrocarbon shipping tankers, oil refineries, and gas plants require certain specifications for the fluids that each receive.
Also, environmental constraints exist for the safe and acceptable handling of hydrocarbon fluids and disposal of produced salt water. It is therfore necessary to process the produced fluids in the field to yield products that meet the specifications set by the customer and are safe to handle.

I. CRUDE OIL PROCESSING
Crude oil–gas–water mixtures produced from wells are generally directed, through flow lines and mainfold system, to a central processing and treatment facility normally called the gas–oil separation plant (GOSP). The first step in processing of the produced stream is the separation of the phases (oil, gas, and water) into separte streams. This takes place in mechanical devices known as two-phase gas–oil separators when the produced stream contains no water or three-phase separators when the produced stream contains water. Gas–oil separation carried out in these separators is recognized as the backbone process in a train of field processing units of oil and gas operations. The separators are used to relieve the excess pressure due to the gas associated with the produced crude and, consequently, separating it from the oil. When water exists in the produced stream, separators are also used to separate the free water from the oil. Once separation is done, each stream undergoes the proper processing for further field treatment, as shown in Fig. 1.

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Baker Hughes Well Site Geology

• Title : Baker Hughes Well Site Geology
• Publish : Baker Hughes INTEQ Technical Publications Group 2001 Rankin Road Houston, TX 77032
• Type Document : pdf
• Release : April 1996
• Total Page : 234 page
• Size : 3.76 Mb

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Baker Hughes Surface Loging System

• Title : Baker Hughes Surface Loging System
• Publish : Baker Hughes INTEQ Technical Publications Group 2001 Rankin Road Houston, TX 77032
• Type Document : pdf
• Release : July 1996
• Total Page : 138 page
• Size : 3.35 Mb

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Drill Cuttings Evaluation
There is no substitute for accurately logged and collected samples! It can not be stressed enough about the importance of good depth control and sample retrieval techniques. Even though the cuttings will be looked at by members of the mud-logging crew, they often spend more time actually catching the samples and maintaining equipment, hence, the samples are given only a perfunctory look. The onus is on the Wellsite Geologist to provide a detailed description of the drilled cuttings.

Those rock samples can be obtained from several sources at the rig site: 

• Shale Shakers (upper & lower screens)
• Desanders, Desilters and Mud-Cleaners (not lagged)
• Flowline and Possum Belly (not lagged)

At the shale shaker, it is essential that the geologist know the shaker screen sizes, and the grain-size of the cuttings that can be recovered from each screen. A representative sample should be caught from a combination of the screens, not just the top or bottom screen.
While it is desirable to use the finest shaker screens at all times, this is impractical due to high flow rates or when using heavy, viscous mud systems. When this happens, samples can be obtained from the desanders and desilters. These devices recover fine solids from the mud system and should always be checked during routine or top hole drilling. When drill breaks or clastic reservoir sections are expected, then more regular samples should be examined to check for the presence of very fine grained clastics. 

When the centrifuge is used to recover very fine material, it should also be checked for very fine clastics (if weighted mud systems are used, the mudcleaner will not be run to prevent excessive barite removal). Samples may also be obtained directly from the flowline using either a very fine sieve or a mudcup and sieve.

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Baker Hughes ESP Electric Submersible Pump

• Title : Baker Hughes ESP Electric Submersible Pump
• Publish : Baker Hughes INTEQ Technical Publications Group 2001 Rankin Road Houston, TX 77032
• Type Document : pdf
• Release : N/A
• Total Page : 16 page
• Size : 10.09 Mb

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The Baker l ift Systems Electric Submersible pumping unit is an effective and economical means 01lifting large volumes of fluids from great depths under a vanety of well conditions . Presently, submersible pumping equipmen t can be used to produce as low as 375 BPD (60 mv day) and as high as 8500 BPD (1350 m)/day), or more of fluid from dept hs of 15,000 feet (4570 m) or more. The water cut may also vary within very wide limits - from negligible amounts to almost 100%.
A typical submersible pumping unit (Fig. 1) consists of an electr ic motor, seal section. intake section, multistage centrifugal pump, electric cable, surface installed control panel and transformers . Additional miscellaneous components of installation will normally include means of securing the cable along-side the tubing. wellhead support. check and bleeder valves. etc. Optional equipment may include a downhole sentry tor sens ing bottomhole temperature and pressure.
The elements of a Baker Lift Systems Electri c Submersible Pump are shown in Fig. 2.

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Baker Advanced Wireline & MWD Procedures

• Title : Baker Hughes Advanced Wireline & MWD Procedures Manual
• Publish : Baker Hughes INTEQ Technical Publications Group 2001 Rankin Road Houston, TX 77032
• Type Document : pdf 
• Release : August 1992
• Total Page : 192 page
• Size : 2.69 Mb

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Review Of Wireline Basics
Introduction
The “first” log generated from borehole information was recorded in 1869, when Lord Kelvin recorded the temperature of a shallow hole. In 1927, Marcel and Conrad Schlumberger, with Henri Doll, recorded the first electrical resistivity log at Pechelbron, France. Since then, more than fifty geophysical-type well logs have been introduced to record the various electrical, nuclear, acoustical, thermal, chemical and mechanical properties of the earth.
Without interpretation, the measurements provided by the various logs are not particularly useful. It takes time, knowledge, and experience to convert the raw data into meaningful and practical information. Many of these formation evaluation methods are now used in sophisticated, computerized programs, the input data consisting of raw well log data, and the output being porosity, hydrocarbon type, fluid saturations, and lithology.
 

Exploration with Wireline Logs
The information from wireline logs is used to enhance two principle objectives in the exploration program:

Rock & Reservoir Properties
a. Environment of Deposition

b. Lithology & Mineralogy
c. Radioactivity
d. Porosity Type
e. Fluid Properties & Distribution
f. Formation Pressure
g. Temperature
h. Rock Strength & Elastic Properties

Hydrocarbon Evaluation

a. Correlation

b. Structure

c. Permeability Traps

d. Porosity Type

e. Salinity Traps 

There are several complicating factors which must be dealt with in order to arrive at acceptable values for those formation and hydrocarbon variables. The three most common factors are:

• The borehole is a dynamic system. The mud system willpenetrate the rocks surrounding borehole, and the borehole wall is affected by the drilling process and time (time difference between drilling and the wireline logging runs).
• Matrix and Pore Fluids affect certain tools differently
• Tool Depth of Investigation is relatively shallow.

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Baker Hughes Coiled Tubing Handbook

• Title : Baker Hughes Coiled Tubing Handbook
• Publish : Baker Hughes INTEQ Technical Publications Group 2001 Rankin Road Houston, TX 77032
• Type Document : pdf
• Release : August 1992
• Total Page : 78 page
• Size : 10.05 Mb

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The global oil and gas industry is using coiled tubing for an ever-increasing array of well intervention projects. Coiled tubing offers a number of operational and economic advantages, including: live well intervention, elimination of well kill and potentially damaging heavy-weight kill fl uids, reduced operational footprint, horizontal intervention, and the ability to intervene without a rig. These advantages have led to the development of truly fi t-for-purpose coiled tubing systems from the industry’s largest provider of coiled tubing well intervention solutions – Baker Oil Tools.
 

Baker Oil Tools offers its clients an unparalleled selection of coiled-tubing-conveyed intervention products, services and solutions with which to approach individual well requirements. This handbook was developed to help our clients determine which systems and services will best meet the needs of a particular application. For that reason, we have designed the handbook to highlight system capabilities within eight distinct intervention areas where coiled tubing can offer a highly effective and cost-effi cient alternative. These eight categories are: Well Cleaning, Fishing and Milling, Zone Isolation, Stimulation and Fracturing, Sand Control Completions, Flow Management, Plug and Abandonment, and Sidetracking and Re-entry. 

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Oil & Gas Production Handbook

• Title : Oil & Gas Production Handbook by Havard Devold
• Publish : ABB ATPA Oil and Gas
• Type Document : pdf 
• Release : December 2006
• Total Page : 84 Page
• Size : 4.75 Mb

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Well Casing
Installing well casing is an important part of the drilling and completion process. Well casing consists of a series of metal tubes installed in the freshly drilled hole. Casing serves to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out of the well hole as it is brought to the surface, and to keep other fluids or gases from seeping into the formation through the well. A good deal of planning is necessary to ensure that the proper casing for each well is installed. Types of casing used depend on the subsurface characteristics of the well, including the diameter of the well (which is dependent on the size of the drill bit used) and the pressures and temperatures experienced throughout the well. In most wells, the diameter of the well hole decreases the deeper it is drilled, leading to a type of conical shape that must be taken into account when installing casing. The casing is normally cemented in place. Ill: wikipedia.org

There are five different types of well casing. They include: 

• Conductor casing, which is usually no more than 20 to 50 feet long, isinstalled before main drilling to prevent the top of the well from caving inand to help in the process of circulating the drilling fluid up from the bottom of the well. 
• Surface casing is the next type of casing to be installed. It can be anywhere from 100 to 400 meters long, and is smaller in diameter than the conductorcasing and fits inside the conductor casing. The primary purpose of surfacecasing is to protect fresh water deposits near the surface of the well from being contaminated by leaking hydrocarbons or salt water from deeperunderground. It also serves as a conduit for drilling mud returning to thesurface, and helps protect the drill hole from being damaged during drilling. 
• Intermediate casing is usually the longest section of casing found in a well. The primary purpose of intermediate casing is to minimize the hazards thatcome along with subsurface formations that may affect the well. Theseinclude abnormal underground pressure zones, underground shales, andformations that might otherwise contaminate the well, such as underground salt-water deposits. Liner strings are sometimes used instead of intermediatecasing. Liner strings are usually just attached to the previous casing with'hangers', instead of being cemented into place and is thus less permanent. 
• Production casing, alternatively called the 'oil string' or 'long string', is installed last and is the deepest section of casing in a well. This is the casing that provides a conduit from the surface of the well to the petroleum producing formation.

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