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Three-Phase Oil–Water–Gas Separators

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.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 are basically similar in shape and components. Further, the same design
concepts and procedures are used for both types of vessel.

read also Gas - Oil Separators

Three-phase separators may be either horizontal or vertical pressure vessels similar to the two-phase separators However, three-phase separators will have additional control devices and may have additional internal components. In the following sections, the two types of separator (horizontal and vertical) are described and the basic design equations are developed.

Horizontal Three Phase Separators
Horizontal-Three-Phase-Separators

Three-phase separators differ from two-phase separators in that the liquid collection section of the three-phase separator handles two immiscible liquids (oil and water) rather than one. This section should, therefore, be
designed to separate the two liquids, provide means for controlling the level of each liquid, and provide separate outlets for each liquid. figure above show schematics of two common types of horizontal three-phase separators. The difference between the two types is mainly in the method of controlling the levels of the oil and water phases. An interface controller and a weir provide the control. The design of the second type , normally known as the bucket and weir design, eliminates the need for an interface controller.
The operation of the separator is, in general, similar to that of the two-phase separator. The produced fluid stream, coming either directly from the producing wells or from a free-water knockout vessel, enters the separator and hits the inlet diverter, where the initial bulk separation of the gas and liquid takes place due to the change in momentum and difference in fluid densities. The gas flows horizontally through the gravity settling section (the top part of the separator) where the entrained liquid droplets, down to a certain minimum size (normally 100 mm), are separated
by gravity. The gas then flows through the mist extractor, where smaller entrained liquid droplets are separated, and out of the separator through the pressure control valve, which controls the operating pressure of the
separator and maintains it at a constant value. The bulk of liquid, separated at the inlet diverter, flows downward, normally through a downcomer that directs the flow below the oil–water interface. The flow of the liquid through the water layer, called water washing, helps in the coalescence and separation of the water droplets suspended in the continuous oil phase. The liquid collection section should have sufficient volume to allow enough time for the separation of the oil and emulsion from the water. The oil and emulsion layer forming on top of the water is
called the oil pad. The weir controls the level of the oil pad and an interface controller controls the level of the water and operates the water outlet valve. The oil and emulsion flow over the weir and collect in a separate compartment, where its level is controlled by a level controller that operates the oil outlet valve.
The relative volumes occupied by the gas and liquid within the separator depend on the relative volumes of gas and liquid produced. It is a common practice, however, to assume that each of the two phases occupies 50% of the separator volume. In such cases, however, where the produced volume of one phase is much smaller or much larger than the other phase, the volume of the separator should be split accordingly between the phases. For example, if the gas–liquid ratio is relatively low, we may design the separator such that the liquid occupies 75% of the separator volume and the gas occupies the remaining 25% of the volume. The operation of the other type of horizontal separator differs only in the method of controlling the levels of the fluids. The oil and emulsion flow over the oil weir into the oil bucket, where its level is controlled by a simple level controller that operates the oil outlet valve.

read also Two-Phase Gas - Oil Separation

The water flows through the space below the oil bucket, then over the water weir into the water collection section, where its level is controlled by a level controller that operates the water outlet valve. The level of the liquid in the separator, normally at the center, is controlled by the height of the oil weir. The thickness of the oil pad must be sufficient to provide adequate oil retention time. This is controlled by the height of the water weir relative to that of the oil weir.

Vertical Three-Phase Separators 

3 phase vertical separatorthe horizontal separators are normally preferred over vertical separators due to the flow geometry that promotes
phase separation. However, in certain applications, the engineer may be forced to select a vertical separator instead of a horizontal separator despite the process-related advantages of the later. An example of such applications is found in offshore operations, where the space limitations on the production platform may necessitate the use of a vertical separator.
The produced fluid stream enters the separator from the side and hits the inlet diverter, where the bulk separation of the gas from the liquid takes place. The gas flows upward through the gravity settling sections which are designed to allow separation of liquid droplets down to a certain minimum size (normally 100 mm) from the gas. The gas then flows through the mist extractor, where the smaller liquid droplets are removed. The gas leaves the separator at the top through a pressure control valve that controls the separator pressure and maintains it at a constant value.
The liquid flows downward through a downcomer and a flow spreader that is located at the oil–water interface. As the liquid comes out of the spreader, the oil rises to the oil pad and the water droplets entrapped in the oil settle down and flow, countercurrent to the rising oil phase, to collect in the water collection section at the bottom of the
separator. The oil flows over a weir into an oil chamber and out of the separator through the oil outlet valve. A level controller controls the oil level in the chamber and operates the oil outlet valve. Similarly, the water out of the spreader flows downward into the water collection section, whereas the oil droplets entrapped in the water rise, countercurrent to the water flow, into the oil pad. An interface controller that operates the water outlet valve controls the water level.

The use of the oil weir and chamber in this design provides good separation of water from oil, as the oil has to rise to the full height of the weir before leaving the separator. The oil chamber, however, presents some problems. First, it takes up space and reduces the separator volume needed for the retention times of oil and water. It also provides a place for sediments and solids to collect, which creates cleaning problems and may hinder the flow of oil out
of the vessel. In addition, it adds to the cost of the separator.Liquid–liquid interface controllers will function effectively as long as there is an appreciable difference between the densities of the two liquids.

In most three-phase separator applications, water–oil emulsion forms and a water–emulsion interface will be present in the separator instead of a water–oil interface. The density of the emulsion is higher than that of the
oil and may be too close to that of the water. Therefore, the smaller density difference at the water–emulsion interface will adversely affect the operation of the interface controller. The presence of emulsion in the separator takes up space that otherwise would be available for the oil and/or the water. This reduces the retention time of the oil and/or water and, thus results in a less efficient oil–water separation. In most operations where the presence of emulsion is problematic, chemicals known as deemulsifying agents are injected into the fluid stream to mix with the
liquid phase. Another method that is also used for the same purpose is the addition of heat to the liquid within the separator. In both cases, however, the economics of the operations have to be weighted against the technical constraints.

Separation Theory 
in general, valid for three-phase separators. In particular, the equations developed for separation of liquid
droplets from the gas phase, which determined the gas capacity constraint, are exactly the same for three-phase separators.
Treatment of the liquid phase for three-phase separators is, however, different from that used for two-phase separators. The liquid retention time constraint was the only criterion used for determining the liquid capacity of two-phase separators. For three-phase separators, however, the settling and separation of the oil droplets from water and of the water droplets from oil must be considered in addition to the retention time constraint. Further, the retention time for both water and oil, which might be different, must also be considered.
In separating oil droplets from water, or water droplets from oil, a relative motion exists between the droplet and the surrounding continuous phase. An oil droplet, being smaller in density than the water, tends to move vertically upward under the gravitational or buoyant force, that the droplet settling velocity is inversely proportional to the viscosity of the continuous phase. Oil viscosity is several magnitudes higher than the water viscosity. Therefore,
the settling velocity of water droplets in oil is much smaller than the settling velocity of oil droplets in water. The time needed for a droplet to settle out of one continuous phase and reach the interface between the two phases depends on the settling velocity and the distance traveled by the droplet. In operations where the thickness of the oil pad is larger than the thickness of the water layer, water droplets would travel a longer distance to reach the water–oil interface than that traveled by the oil droplets. This, combined with the much slower settling velocity of the water droplets, makes the time needed for separation of water from oil longer than the time needed for separation of oil from water. Even in operations with a very high water–oil ratio, which might result in having
a water layer that is thicker than the oil pad, the ratio of the thickness of the water layer to that of the oil pad would not offset the effect of viscosity. Therefore, the separation of water droplets from the continuous oil phase would always be taken as the design criterion for three-phase separators.
The minimum size of the water droplet that must be removed from the oil and the minimum size of the oil droplet that must be removed from the water to achieve a certain oil and water quality at the separator exit depend largely on the operating conditions and fluid properties. Results obtained from laboratory tests conducted under simulated field conditions provide the best data for design. The next best source of data could be obtained from nearby fields. If such data are not available, the minimum water droplet size to be removed from the oil is taken as 500 mm.
Separators design with this criterion have produced oil and emulsion containing between 5% and 10% water. Such produced oil and emulsion could be treated easily in the oil dehydration facility.

Retention Time

Another important aspect of separator design is the retention time, which determines the required liquid volumes within the separator. The oil phase needs to be retained within the separator for a period of time that is sufficient for the oil to reach equilibrium and liberates the dissolved gas.
The retention time should also be sufficient for appreciable coalescence of the water droplets suspended in the oil to promote effective settling and separation. Similarly, the water phase needs to be retained within the separator for a period of time that is sufficient for coalescence of the suspended oil droplets. The retention times for oil and water are best determined from laboratory tests; they usually range from 3 to 30 min, based on operating conditions and fluid properties. If such laboratory data are not available, it is a common practice to use a retention time of 10 min
for both oil and water.

References:
1. Oil and gas Production Handbook.
2. Oil and Gas Field Processing – King Fahd University of Petroleum and Minerals.

Reservoir Simulation Data Management

Reservoir Simulation Data Management

Eng.Ali Yahya Jirjees Salman


Introduction
Data from a wide variety of sources are required for reservoir simulation. Simulation itself produces large quantities of data. Yet, good data management practices for reservoir simulation data are typically neither well-understood nor widely investigated.
Reservoir simulation is inherently a data-intensive process. It starts with geological models and their properties, and assignment of phase behavior or equation of state data, relative permeability and capillary pressure information and geo-mechanical data. It requires layout of the surface facility network, subsurface configuration of wells, their attributes, pressure and rate limits and other production and optimization constraints. Very often, production history information, hydraulics tables, completion tables and logic for runtime management of wells and surface facilities are needed. Finally, special cases like thermal and fractured reservoir simulations require their own set of additional data.

During simulation, time-stepping information, convergence parameters and well performance data can be logged and analyzed. Results, such as pressures and rates from wells and surface facilities and pressures and saturations from the simulation grid can be monitored and recorded. The state of the simulator can be recorded at specified intervals to enable restart of a run at a later time.

This result in an abundance of data to be analyzed, visualized, summarized, reported and archived. Over the years, many authors have tried to address one aspect or another of this data management problem and many commercial and proprietary simulators have made allowances to simplify users’ work in this area. However, in general, data management has not been a widely investigated aspect of reservoir simulation.

Data management in reservoir simulation enables workflows and collaboration, insures data integrity, security and consistency and expedites access to results. In today’s computing environment, data management is an enabler to meet the growing need for reservoir simulation and to make simulation available to a wider audience of professionals, including many kinds of engineers and geoscientists.

Reservoir Management

The main goal of oil reservoir management is to provide more efficient, cost-effective and environmentally safer production of oil from reservoirs. Implementing effective oil and gas production requires optimized placement of wells in a reservoir. A production management environment involves accurate characterization of the reservoir and management strategies that involve interactions between data, reservoir models, and human evaluation. In this setting, a good understanding and monitoring of changing fluid and rock properties in the reservoir is necessary for the effective design and evaluation of management strategies. Despite technological advances, however, operators still have at best a partial knowledge of critical parameters, such as rock permeability, which govern production rates; as a result, a key problem in production management environments is incorporating geologic uncertainty while maintaining operational flexibility.

Combining numerical reservoir models with geological measurements (obtained from either seismic simulations or sensors embedded in reservoirs that dynamically monitor changes in fluid and rock properties) can aid in the design and implementation of optimal production strategies. In that case, the optimization process involves several steps:

1. Simulate production via reservoir modeling;
2. Detect and track changes in reservoir properties by acquiring seismic data (through field measurements or seismic data simulations);
3. Revise the reservoir model by imaging and inversion of output from seismic data simulations.

Reservoir Simulation

As stated earlier, one challenging problem in the overall process is incorporating geological uncertainty. An approach to address this issue is to simulate alternative production strategies (number, type, timing and location of wells) applied to multiple realizations of multiple geo-statistical models. In a typical study, a scientist runs an ensemble of simulations to study the effects of varying oil reservoir properties (e.g. permeability, oil/water ratio, etc.) over a long period of time. This approach is highly data-driven. Choosing the next set of simulations to be performed requires analysis of data from earlier simulations.

Another major problem is the enormity of data volumes to be handled. Large-scale, complex models (several hundreds of thousands of unknowns) often involve multiphase, multicomponent flow, and require the use of distributed and parallel machines. With the help of large PC clusters and high performance parallel computers, even for relatively coarse descriptions of reservoirs, performing series of simulations can lead to very large volumes of output data. Similarly, seismic simulations can generate large amounts of data. For example, downhole geophysical sensors in the field and ocean bottom seismic measurements are episodic to track fluid changes. However, per episode, these involve a large number (e.g. hundreds to thousands) of detectors and large numbers of controlled sources of energy to excite the medium generating waves that probe the reservoir.

These data are collected at various time intervals. Thus, seismic simulators that model typical three-dimensional seismic field data can generate simulation output that is terabytes in size. As a result, traditional simulation approaches are overwhelmed by the vast volumes of data that need to be queried and analyzed.

We can state now a definition of reservoir management process which is the utilization of the available resources (i.e., human, technological and financial)) in order to:
1. Maximize benefits (profits) from a reservoir by optimizing recovery.
2. Minimizing capital investments and operating expenses.

Objectives of Reservoir Management

Data replication is common across reservoir simulation models. Initially, a few base reservoir simulation models were available for a reservoir, e.g., P10, P50, and P90 models. These models are used extensively used to explore and evaluate different field development plans or field management strategies. As a result of exploration or evaluation, many more models are derived from these base reservoir models. A derived reservoir model is usually created in two steps:

1. Copying a base reservoir model.
2. Modifying parameter values in the copy.

Furthermore, the derived models can also be used to derive new models. Data replication poses many challenges to reservoir simulation model management. The first challenge is the efficiency of management. Data replication results in new relationships among models. The new relationships can be created based on data components shared by various models. Managing these relationships results in overhead. For example, additional metadata used to track the relationships must be captured and stored. The second challenge caused by data replication is maintaining data consistency among various reservoir simulation models.

Generally, the more one replicates, the more points of divergence are created and the more one is subject to incorrect behaviors. On the other hand, base reservoir simulation models are regularly updated or calibrated as historical production data of the reservoir become available (the process is called history matching in petroleum engineering). Due to the complexity of a reservoir simulation model, propagating changes in these base models properly and efficiently is nontrivial.

So we can summarize the objectives for managing the reservoir in the following points:

– Decrease risk.
– Increase oil and gas production.
– Increase oil and gas reserves.
– Minimize capital expenditures.
– Minimize operating costs.
– Maximize recovery.
– Identify and define all individual reservoirs in a particular field and their physical properties.
– Deduce past and predict future reservoir performance.
– Minimize drilling of unnecessary wells.
– Define and modify (if necessary) wellbore and surface systems.
– Initiate operating controls at the proper time.
– Consider all pertinent economic and legal factors.

Why and when should reservoir management be used?

The ideal time to start managing a reservoir is at its discovery, because:

  1. Early initiation provides a better monitoring and evaluation tool,
  2. Costs less in the long run.

A good example of that can be an extra log or an additional hour’s time on a DST may provide better information than could be obtained from more expensive core analysis. It is possible to do some early tests that can indicate the size of a reservoir. If it is of limited size, drilling of unnecessary wells can be prevented.

The magnitude of the investments associated with developing oil and gas assets motivates the consideration of methods and techniques that can minimize these outlays and improve the overall economic value. For several decades, industry practices have attempted to address this issue by considering a variety of approaches that can be referred to collectively as traditional methods. These methods include trial-and-error approaches that conduct a series of “what if” analyses or case studies as well as heuristic and intuition-based efforts that impose rules and learning on the basis of experience or analogies. In contrast, mathematical-optimization techniques can provide an efficient methodology toward achieving these goals by combining all the traditional approaches into a comprehensive and systematic process.

We can overview a case history that shows the effect on production targets between the use of reservoir management and without it.

The case includes the development of a regional complex of gas reservoirs similar to those found in the Gulf of Mexico, the southern gas basin of the North Sea, West Africa, and in basins in the Far East is examined. The example in this paper is an amalgamation of the fields typically developed around the world.

The complex to be developed consists of three main fields with at least one additional satellite. It is assumed that several development decisions have already been made when this work commences. For example, the gas in place for each reservoir; the size, configuration, and number of platforms; and the pipeline infrastructure have been determined or specified. The layout of the reservoirs and infrastructure is shown below.Reservoir Simulation

The Reservoir A platform has eight well slots, with each well costing U.S. $15 million. Sand production and water coning place flow limitations on the different wells, ranging from 10 to 25 MMscf/D. Water influxes occurs in Reservoir A, although the relatively high production rates limit the support to approximately 100 psi for the period of interest. Flow limitations for wells in Reservoirs B and C are comparable to wells in Reservoir A, although Reservoir B does contain one well that can produce up to 30 MMscf/D. The total gas handling capacity at the terminal is 200 MMscf/D, and the gas must be delivered at a pressure of at least 900 psi.And here is a schematic graphs show the great difference in producing the different cases with the use of reservoir management and without.

Reservoir SimulationA brief description of the cases considered is provided in the following table, and the economic results of these cases are summarized in the following Figure. This figure shows the cases without mathematical optimization in the upper left portion. Capital efficiency is improved by simultaneously lowering capital costs while increasing production, as demonstrated by the optimized cases in the lower right portion of the graph. The comparison demonstrates the advantage of an optimization-based approach to reservoir management that completely integrates the workflow to make decisions that drive capital investment, scheduling, production, recovery, and, ultimately, asset performance.

The highly nonlinear nature of the physical system and the combinatorial complexity of development decisions warrant the proper modeling of the assets, the appropriate formulation of the optimization systems, and the use of tailored state-of-the-art mathematical techniques to render these numerical systems tractable. However, the considerable economic benefits, as demonstrated in this paper, provide the motivation for use of these techniques. Because most of the capital-investment commitments are made in the early life of an asset, a narrow window of opportunity exists to influence the economic performance of the asset. Thus, there is a clear need to apply such technology at the earliest opportunity.

Reservoir Simulation

Reservoir Management Team Involved

Reservoir management process should be through a team approach in order to:

– Facilitate communication among various engineering disciplines, geology, and operations.
– The engineer must develop the geologist’s knowledge of rock characteristics and depositional environment, and a geologist must cultivate knowledge in well completion and other engineering tasks, as they relate to the project at hand.
– Each member should subordinate their ambitions and egos to the goals of the reservoir management team.
– Each team member must maintain a high level of technical competence.
– Reservoir engineers should not wait on geologists to complete their work and then start the reservoir engineering work. Rather, a constant interaction between the functional groups should take place.

The reservoir management team should include the following elements at any company:

1.  Management.
2. Geology and geophysics.
3. Reservoir engineering.
4. Economics and finance.
5. Drilling engineering.
6. Design and construction engineering.
7. Production and operation engineering.
8. Gas and chemical engineering.
9. Research and development.
10. Environment.
11. Legal and landlords.
11. Services provider.

Reservoir Management Process

The process of managing the reservoir includes:

  • Setting strategy (goals): The key elements for setting the reservoir management goals are:
  1. Reservoir characteristics.
  2. Total environment.
  3. Available data.
  • Developing a plan:
  1. Development and depletion strategy
  2. Environmental consideration.
  3. Data acquisition and analysis.
  1. Geological & numerical model studies
  2. Production and reserve forecast.
  3. Facilities requirement.
  4. Economic optimization.
  1. Management approval.
  • Implementation:
  1. Start with a plan of action, involving all functions.
  2. Flexible plan.
  3. Management support.
  4. Commitment of field personal.
  1. Periodic review meeting, involving all team members.
  • Monitoring.
  • Evaluation.
  • Completing.

 

  • Reasons of Failure Of Reservoir Management:
  1. Un-integrated system.
  2. Starting too late.
  1. Lack of maintenance.
  2. Having multiple bosses.
    5. Data non-continuity & unreliability.

Data Management

Throughout the life of a reservoir, from exploration to abandonment, an enormous amount of data are collected. An efficient data management program consisting of acquisition, analysis, validating, storing, and retrieving plays a key role in reservoir management.

List of data types in reservoir simulation process:Reservoir Simulation TypesReservoir Simulation TypesManagement of reservoir simulation models includes two tasks. One is the management of models’ data files. In a file-based approach, the management mainly concerns the directory hierarchy for storing the models, including naming of the data files and directories. The second task is the management of relationships between the models, such as data sharing.
Two models are considered to have a data sharing relationship if they share a portion of their model data. For example, two models might share the same historical production data and well completion data. Data sharing relationships are very common among reservoir simulation models. However, data sharing among simulation models results in data replicas. The complete data of a model are typically stored in a repository managed by traditional approaches. If part of a model is shared by multiple models, multiple replicas of the data are created and distributed in each of those models.

These data replicas cause two problems to the repository. The first is concerned with the storage efficiency. The second is related to data consistency among the models with shared data components. In an oilfield asset, reservoir simulation models are regularly updated or calibrated as historical production data of the reservoir become available (the process is called history matching in petroleum engineering). Due to the complexity of a reservoir simulation model, propagating changes in these models properly and efficiently is a nontrivial task. Therefore, reducing data replicas in the repository is desirable in the management of reservoir simulation models.
Data replication has been studied extensively in the area of distributed systems. Previous research efforts can be classified into two categories. The first category focuses on data replication across a distributed system to improve reliability, fault-tolerance, or accessibility of the system. The second category addresses data consistency resulting from data replication. Replica consistency techniques and systems have been developed for this purpose. However, to the best of our knowledge, no existing work has addressed the data replica problem in the management of simulation models.

 Reasons of Failure

  1. Un-integrated systems.
  1. Starting too late.
  2. Lack of maintenance.
  3. Having multiple bosses.
  4. Data non-continuity and unreliability.

 

    References

  • Integrated Petroleum Reservoir Management Abdus Satter, Ph.D. ,Research Consultant , Texaco E&P Technology Department , Houston, Texas / Ganesh C. Thakur, Ph.D. , Manager-Reservoir Simulation Division , Chevron Petroleum Technology Company , La Habra, California.
  • Applying Optimization Technology in Reservoir Management

               Vasantharajan, Optimal Decisions Inc.; R. Al-Hussainy, Amerada Hess Ltd.; and R.F. Heinemann, Berry
Petroleum Co.

  • A simulation and data analysis system for large-scale, data-driven oil reservoir simulation studies, Pract. Exper. 2005; 17:1441–1467, Tahsin Kurc1,†, Umit Catalyurek1, Xi Zhang1, Joel Saltz1, Ryan Martino2, Mary Wheeler2, Małgorzata Peszy´nska3.

Removing H2S from Oil

1、INTRODUCTION
Sulfur compounds exist in various light oils made from petroleum. Such as mercaptan, hydrogen sulfide, which cause foul odors and deteriorate the finished products. In addition, due to their acidity, they are corrosive to metals, which is harmful for storage and usage of oil products. Therefore, it is necessary to remove them.
In the refining industry, an aqueous base such as sodium hydroxide or ammonia is employed fulfilling the purpose. Although its effectiveness and the low cost of fresh caustic are the reasons for its widespread use, the aqueous base especially sodium hydroxide always causes some problems. Such as spending many caustic materials, and discarding lots of hazardous waste. So environmental agencies around the world have tightened the regulations aimed at controlling its disposal. Solid bases merge as an ideal alternative to the aqueous bases to overcome the environmental and economic problems. The report concerning solid base is mostly concentrate in mercaptan oxidation, these solid bases selected from the group consisting of magnesium, nickel, zinc, copper, aluminum, iron oxides and mixtures thereof. However the report concerning solid base on removal of hydrogen sulfide was hardly consulted.
This paper reports the effect of factors of preparation for the solid base on removal of hydrogen sulfide at ambient temperature.
Thus selecting the optimum factor of preparation for the solid base on the removal of hydrogen sulfide in light oil.
2. EXPERIMENTAL
2.1 Preparation of solid base
Activated carbon marked by DV-01was used as supporter in this study. The activated carbon was calcined at high temperature for 6h, then impregnated with a aqueous solution of some alkalic materials at ambient temperature. The saturated activated carbon was filtrated in vacuum for period of time, then dried period of time at special
temperature.
Experimental Oil
Petroleum ether(boiling point 90—120℃) was used as experimental oil with 800—1000μg/g hydrogen sulfide
concentration.
Capability test of solid base for the removal of hydrogen sulfide
1g solid base was loaded in a 200ml flask, to this flask 100ml experimental oil was added, then the solution was electromagnetism stirred at ambient temperature with protection of nitrogen, the stirred speed was 350rpm. The hydrogen sulfide concentration in light oil was analyzed with period by the method of GB/T1792-88.

Materials calculation
The adsorption quantity of solid base for hydrogen sulfide as follows: Xg = (C0-Ct)•ρV•10-3/M
where
Xg: the adsorption quantity of the solid base for hydrogen sulfide mg/g
C0: Preliminary concentration of hydrogen sulfide μg/g
Ct: concentration of hydrogen sulfide at t hour μg/g
ρ、V: density, vol. of oil g/ml, ml
M: the quality of the used solid base g

The effect of different chemical components of solid base on the removal of H2S
With different alkalic materials, six kinds of solid base were prepared and the removal capacities for H2S were tested. , the SB15 solid base for absorption of hydrogen sulfide has the highest capacity.
The solid base adsorption for hydrogen sulfide has a competitive between physical adsorption and chemical adsorption.
The removal capacity for hydrogen sulfide of the solid base was the sum of physical adsorption and chemical adsorption. Different solid base has different surface area and chemical center, so the capacity for hydrogen sulfide removal is alternatively. SB15 has the best chemical components.

The effect of solid base vacuum filtration time on the removal of H2S
Experiments examine the effect of time of vacuum filtration during preparation of the solid base for the removal of hydrogen sulfide. The activated carbon was impregnated with the optimum concentration of aqueous, then the loaded activated carbon was vacuum filtrated by different time, thereby making A series of solid bases.

the adsorption capacity of the solid base for hydrogen sulfide firstly increased and then decreased with the increase of the vacuum filtration time during the preparation of the solid base. As a result, the time of vacuum filtration is a major factor for the solid base on removal of hydrogen sulfide, the optimum time of vacuum filtration should be 60 min.

The effect of solid base drying time on the removal of H2S
A series of solid bases were made with different time of drying from short to long. And the removal of hydrogen sulfide of these solid bases were examined.

the adsorption quantity of the solid base for hydrogen sulfide firstly increased then decreased with the time of
drying prolonged in the preparation of the solid base. The shorter the time of drying is, the higher the water content of the solid base is, the higher water content of the solid base reduced the physical adsorption of the solid base for hydrogen sulfide. With the further drying, the water is so less in the solid base that can not provide the polar
environment for the chemical adsorption. consequently the chemical adsorption quantity of hydrogen sulfide in the solid base was decreased greatly.
It was found that the optimum time of drying for the solid base with good properties should be 2 hr.

The effect of additive on the removal of H2S
It is believed that the function of polar compound is to serve as a proton transfer medium in the chemical reaction. Specially the compounds are selected from the group consisting of water, alcohols, esters, ketones, diols and mixtures thereof. A group of polar compounds was chosen as the additive for the solid base for removal
of H2S. Experiments were carried out for measuring the adsorption capacity of the solid base with different quantity of the additive.

the additive was added, thus the adsorption of the solid base for hydrogen sulfide has greatly increased.

CONCLUSIONS
1.Preparation factors of the solid base play an important role for the solid base on removal of hydrogen sulfide. The preparation factors include the components of solid base, the time of vacuum filtration and the time of drying.
2. The adsorption capacity of the solid base for hydrogen sulfide was the sum of physical adsorption and chemical adsorption.
3. Adding a group of polar compounds can promote significantly the removal of hydrogen sulfide by the solid base. The optimum quantity of the additive is 6000 μg/g.

Wells – Chemicals

Chemicals Used in Fracturing

The identities of chemicals incorporated in fracturing fluids were probably the first thing sensationalized about fracturing. The movie “Gasland” created quite a stir with the statement that a “cocktail” of several hundred toxic chemicals were “potentially” used in fracturing. The grain of truth was that there are many chemicals in additives sold for incorporation in fracturing; however; the fact is that most fracs use only a dozen or so major chemicals, some of which are food-grade additives and many are in parts per million concentration. About half of fracturing jobs are “slick water” fracturing fluid that often use low concentrations of two to five chemicals. Many claims of chemical usage also include trace amounts of chemicals at the edge of detection and most well below the EPA’s strictest limits. Analysis of drinking water, for comparison, has shown arsenic, lead, chromium, solvents, gasoline, pesticides, prescription drugs, and a myriad of household products as the most common contaminants – none from fracturing. The upside to this commentary is that public concerns have moved chemical manufacturers to make and operators to use safer chemicals and less overall chemicals. Many companies have moved toward biocides with less residual activity, mechanical biocides such as ultraviolet light and the use of chemicals on the US EPA’s Safer Choice chemicals (formerly Designed For Environment or DfE) or UK North Sea’s OCNS Hazard rating of Gold Band (lowest possible hazard quotient). These listed materials meet requirements of rapid biodegradation and minimum harm to environments.

see our Drilling Video Course

Friction reducer, the largest volume chemical in slick water fracs, is polyacrylate, a polymer whose main use is in baby diaper absorbent and as a drinking water purifier that adsorbs heavy metals. A cross section of chemicals used in fracturing, the volumes used and some alternate uses helps explain oil field fracturing chemical usage. Chemicals such as diesel, benzene and proven carcinogens, mutagens and endocrine disruptors are not used in modern safe fracturing fluids. The CAS number identifies exact identity (no “trade secret” identities).

drilling chemicals

One of the most impactful problems from fracturing in Pennsylvania was the use of local water treating plants to treat water produced from oil and gas wells before disposal into Pennsylvania rivers. The practice was evidently instituted in Pennsylvania decades prior to the shale drilling boom in the Marcellus when volumes of water flowed from conventional wells was very small and natural salt contents were low. Dilution of locally severe acid mine drainage in some creeks by the produced water was expected to be beneficial; however; large volumes of produced water from fracturing in the shales with high salinity and ions such as bromine and barium proved too problematic for such a disposal method. This practice, although allowed by law in Pennsylvania until about 2010, has been forbidden by law in nearly all western states since the 1950’s.

read also Drilling Rotating Equipment

Chemicals Used in Production Operations

Producing oil and gas with the associated salt water from hydrocarbon bearing formations creates corrosion potential, flow restriction deposits such as mineral scales of calcium or barium and challenges in separating oil from water. Corrosion remains one of the biggest deterioration problems in the oil industry (a large problem in other industries as well). Scales may precipitate in tubulars until they restrict flow. Paraffins (wax) are longer carbon chain components of oil and can deposit anywhere in the well as temperatures cool and pressure declines. Mixing of salt water, oil, gas and a small amount of solids such as sand, rust or even ice can produce emulsions, froths and foams that must be separated before the oil and gas can be sold and the salt water can be recycled or properly re-injected into the hydrocarbon producing formation. A wide variety of specialty chemicals, often at part per million (ppm) concentration, can be used, but only a handful of products are typically selected after laboratory testing. Using minimum amounts of the best additives reduces cost and risk in transport or storage.

drilling chemicals

Any chemical usage may be frightening to some people and there are definitely chemicals that should not be used, particularly where contamination or airborne emissions are possible. By using chemicals proven safe for specific uses, all elements of potential pollution are reduced. Even when the chemicals will never be disposed of in the environment outside of oilfield containment, the safe chemical route minimizes impact in the event of a spill or leak.
Note: BTX (Benzene, Toluene, Xylene) content in many additives is steadily declining but some operators have not phased the products out completely. Many companies are reviewing product offerings for the BTX or other troublesome materials and choosing alternatives. Although BTX is often reported in wells as if they were part of a chemical additive, the most likely source is in the produced oil. BTX and diesel range oil components are a natural part of many produced oils.

Chemicals Used in Crude Oil Production

Petroleum
“A complex combination of hydrocarbons. It consists predominantly of aliphatic, alicyclic and aromatic hydrocarbons. It may also contain small amounts of nitrogen, oxygen and sulfur compounds. This category encompasses light, medium, and heavy petroleums, as well as the oils extracted from tar sands. Hydrocarbonaceous materials requiring major chemical changes for their recovery or conversion to petroleum refinery feedstocks such as crude shale oils,
upgraded shale oils and liquid coal fuels are not included in this definition.”

Oilfield ChemicalsVarious types of chemicals (which themselves can be mixtures or formulations of various chemicals) are required to aid the production, handling and transportation of crude oil. The chemicals used fall into several types as outlined below. For most, only trace amounts may remain in the crude as impurities once it reaches the refinery. This document will review the various types of chemicals used in crude and their role in production.
Most Oilfield production chemicals (OFCs) are complex formulations of many different chemicals. Often the constituent chemicals themselves are not pure chemical species but a mixture of reaction products, reactants, and diluents. The formulation usually has one or two primary ingredients that give the additive its main functionality. In addition, the formulation is specifically designed for each oilfield, and within the oilfield, for each well, and for each well the recipe may vary depending upon the time and the operation conditions. The crude from a number of wells/fields is combined such that it is nearly impossible to ascertain the resulting combination of OFC’s used for a crude oil at a loadport.
Chemicals are used in various stages of oilfield development namely drilling, cementing, well completion, and well stimulation/workover. These chemicals may end up as impurities in the crude oil.
During the production phase, the flow of oil out of the well needs to be assured by preventing the deposition of hydrates, wax, asphaltenes, or scale. Chemicals provide a means for controlling such deposits. The presence of water, bacteria, and acids all result in a corrosive environment. Production of crude oil usually involves a significant bulk water phase, many (OFCs) are water-soluble by design. When used in continuous low dose injection they remain with the water phase at the upstream facilities. The production of oil usually involves its separation from water and gas. A small amount may be present in water droplets dispersed or partitioned in the oil phase as an impurity.

see our Oilfield Chemicals Books section

Additionally chemicals may be needed during the transportation and logistical handling of the crude oil, e.g. in a pipeline, tanker, or terminal. Drag reducing agents can be added in pipelines to improve flow. Pour point depressants, mercaptan scavengers, hydrogen sulfide scavengers are often added to cargoes in order to satisfy shipping or loadport requirements for stability.
Chemicals can be added either by continuous dosage or in batch treatments. The concentration in the crude usually ranges from 10 – 200 ppm. These post-production chemicals help to control corrosion, scale, hydrogen sulfide, bacteria; help to prevent hydrate formation, wax deposition, asphaltene precipitation; and help to resolve emulsions. In other words, they are added to preserve the stability of the crude oil during transport so that the crude can reach the refinery for conversion to products.

Chemical families used in the production and transportation of crude oil include the following:

(1) Scale Inhibitors
Used in the oil production process to prevent the deposition of mineral scale that may occur in the pores of rock formations, in downhole pipework and in surface treating facilities.

(2) Corrosion Inhibitors:
Aqueous acids are used to stimulate production from reservoirs. Such acids expose oil production systems to the possibility of corrosion. Thus corrosion inhibitors are required to protect the downhole pipework and
vessels of oil production facilities.

(3) Oxygen Scavengers:
Often used to mitigate corrosion problems in water injection systems, in hydrotesting and drilling.

(4) Biocides:
Bacterial growth in waters associated with crude oil production is controlled by the use of biocides. Biocides are water-soluble and removed with the water from crude.

(5) Emulsion Breakers:
Production of Oil usually involves the coproduction of large quantities of water. Natural surfactants present in the oil or water, other chemicals such as corrosion inhibitors combined with the shearing effect from
turbulent flow and pumps may create emulsions. Demulsifiers are used to resolve water-in-oil emulsions.

(6) Antifoam Agents:
Foaming problems occur in many oilfield processes. Problems occur when gas breaks out form crude oil in separators, or in gas processing plants.

(7) Drag reducing Agents:
High molecular weight oil-soluble polymeric compounds are added to crude oil pipeline fluids in order to enhance flow and minimize pressure drop. A long pipeline can have more then one injection point.

(8) Hydrate Inhibitors:
Gas hydrates are formed when water molecules crystallize around hydrocarbon molecules at certain pressure and temperature combinations. They can plug flowlines and damage process equipment. In addition to specific chemicals, methanol or glycols (MEG, DEG, TEG) may be used to prevent crystallization of the water molecules.

(9) Hydrogen Sulfide Scavengers:
Hydrogen sulfide in produced oil and gas poses safety and corrosion concerns. Scavengers bind the H2S in a form that is stable in the liquid phase. They can be added at oil production facilities or in transit in a pipeline or
tanker.

(10) Mercaptan Scavengers:
Low molecular weight (C1-C3) mercaptans have offensive odors and are toxic. It is necessary to remove and neutralize them.
Mercaptan scavengers either oxidize the offending species or convert them to less volatile molecules.

(11) Paraffin Control Agents and Pour Point Depressants:
Crude oils may contain varying degrees of long chain paraffins or waxes that tend to form deposits if the oil is subjected to changes in temperature, pressure or other conditions.
Dispersants/detergents are used to remove deposits already formed and inhibitors to interfere with wax crystal growth and formation.

(12) Asphaltene Control Agents:
Asphaltenes can destabilize and precipitate out when temperature, pressure or oil composition changes. Chemicals are added to control asphaltene precipitation.

Offshore Petroleum Platforms

what are offshore platforms?

offshore platformOffshore structures are used worldwide for a variety of functions and in a variety of water depths, and environments. Since right selection of equipment, types of platforms and method of drilling and also right planning, design, fabrication, transportation, installation and commissioning of petroleum platforms, considering the water depth and environment conditions are very important, this post will present a general overview of these aspects. This post reviews the fundamentals behind all types of offshore structures (fixed or floating) and, in the case of fixed platforms, will cover applications of these principles. The overall objective is to provide a general understanding of different stages of design, construction, loadout, transportation and installation of offshore platforms.

Offshore platforms have many uses including oil exploration and production, navigation, ship loading and unloading, and to support bridges and causeways.
Offshore oil production is one of the most visible of these applications and represents a significant challenge to the design engineer. These offshore structures must function safely for design lifetimes of twenty-five years or more and are subject to very harsh marine environments. Some important design considerations are peak loads created by hurricane wind and waves, fatigue loads generated by waves over the platform lifetime and the motion of the platform. The platforms are sometimes subjected to strong currents which create loads on the mooring system
and can induce vortex shedding.

see our Offshore Books section

Offshore platforms are huge steel or concrete structures used for the exploration and extraction of oil and gas from the earth’s crust. Offshore structures are designed for installation in the open sea, lakes, gulfs, etc., many kilometers from shorelines. These structures may be made of steel, reinforced concrete or a combination of both. The offshore oil and gas platforms are generally made of various grades of steel, from mild steel to high-strength steel, although some of the older structures were made of reinforced concrete.
Within the category of steel platforms, there are various types of structures, depending on their use and primarily on the water depth in which they will work.
Offshore platforms are very heavy and are among the tallest manmade structures on the earth. The oil and gas are separated at the platform and transported through pipelines or by tankers to shore.

offshore platforms

read also Offshore Drilling Rigs

Design of offshore fixed platforms

The most commonly used offshore platforms in the Gulf of Mexico, Nigeria, California shorelines and the Persian Gulf are template type platforms made of steel, and used for oil/gas exploration and production (Sadeghi 1989, 2001).
The design and analyses of these offshore structures must be made in accordance with recommendations published by the American Petroleum Institute (API).
The design and analysis of offshore platforms must be done taking into consideration many factors, including the following important parameters:
• Environmental (initial transportation, and in-place 100-year storm conditions)
• Soil characteristics
• Code requirements (e.g. American Institute of Steel Construction “AISC” codes)
• Intensity level of consequences of failure.
The entire design, installation, and operation must be approved by the client.

Environmental parameters

The design and analysis of fixed offshore platforms may be conducted in accordance with the API’s “Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms – Working Stress Design (API-RP-2AWSD)”.
The latest revision of API-RP-2A-WSD is the 21st edition dated December 2000. The API specifies minimum design criteria for a 100-year design storm.
Helicopter landing pads/decks on offshore platforms must conform to API RP-2L (latest edition being the 4th edition, dated May 1996).
Normally, for the analysis of offshore platforms, the environmental parameters include wave heights of as much as 21 meters (depending on the water depth) and wind velocities of 170 km/hr for Gulf of Mexico, coupled with tides of up to 4 m in shallow waters. The wave heights up to 12.2 meters and wind velocities up to 130 km/hr for the Persian Gulf, coupled with tides up to 3 m are considered in design of platforms (Sadeghi 2001).
The design wave height in the Southern Caspian Sea is about 19 m for a return period of 100 years, and for the North Sea is over 32 m depending on the location.
The API RP-2A also specifies that the lowest deck must maintain a minimum of 1.5 m air gap between the bottom of the deck beams and the wave crest during the maximum expected level of water considering the combination of wave height and tides.
The platform should resist the loads generated by the environmental conditions and loadout, transportation and installation loads plus other loads generated by onboard equipment.

A typical offshore structure supported by piles normally has a deck structure containing a Main Deck, a Cellar Deck, Sub-Cellar Deck and a Helideck. The deck structure is supported by deck legs connected to the top of the piles. The piles extend from above the Mean Low Water through the mudline and into the soil.
Underwater, the piles are contained inside the legs of a “jacket” structure which serves as bracing for the piles against lateral loads. The jacket may also serve as a template for the initial driving of the through leg piles (The piles may be driven through the inside of the legs of the jacket structure). In the case of using skirt piles.
the piles may be driven from outside of the legs of the jacket structure. The structural model file consists of:
• The type of analysis, the mudline elevation and water depth.
• Member sizes
• Joints definition.
• Soil data (i.e. mudmat bearing capacity, pile groups, T-Z, P-Y, Q-Z curve points).
• Plate groups.
• Joint coordinates.
• Marine growth input.
• Inertia and mass coefficients (CD and CM) input.
• Distributed load surface areas.
• Wind areas.
• Anode weights and locations.
• Appurtenances weights and locations
• Conductors and piles weight and location
• Grouting weight and locations
• Load cases include dead, live and environmental loading, crane loads, etc.

Any analysis of offshore platforms must also include the equipment weights and a maximum deck live loading (distributed area loading), dead loads in addition to the environmental loads mentioned above, and wind loads. Underwater, the analysis must also include marine growth as a natural means of enlargement of underwater
projected areas subject to wave and current forces.
The structural analysis will be a static linear analysis of the structure above the mudline combined with a static non-linear analysis of the soil with the piles.
Additionally, checks will be made for all tubular joint connections to analyze the strength of tubular joints against punching. The punching shear analysis is colloquially referred to as “joint can analysis”. The Unity Checks must not exceed 1.0.
All structural members will be chosen based on the results of the computer-aided in-place and the other above-mentioned analyses. The offshore platform designs normally use pipe or wide flange beams for all primary structural members.
Concurrently with the structural analysis the design team will start the development of construction drawings, which will incorporate all the dimensions and sizes optimized by the analyses and will also add construction details for the field erection, transportation, and installation of the structure.
The platforms must be capable of withstanding the most severe design loads and also of surviving a design lifetime of fatigue loading. The fatigue analysis is developed with input from a wave scatter diagram and from the natural dynamic response of the platform, and the stiffness of the pile caps at the mudline by applying Palmgeren-Miner formula (Sadeghi 2001). A detailed fatigue analysis should be performed to assess cumulative fatigue damage. The analysis required is a “spectral fatigue analysis” or simplified fatigue analysis according to API.
API allows a simplified fatigue analysis if the platform (API 1996):
• Is in less than 122 m (400 ft) water depth.
• Is constructed of ductile steel.
• Has redundant framing.
• Has natural periods less than 3 seconds.

References:
1. Offshore Platform Design.
2. Installation of Petroleum Offshore Platform.

Gas–Oil Separators part. 2

Inlet Diverters
Inlet diverters are used to cause the initial bulk separation of liquid and gas. The most common type is the baffle plate diverter, which could be in the shape of a flat plate, a spherical dish, or a cone. Another type, is the
centrifugal diverter; it is more efficient but more expensive. The diverter provides a means to cause a sudden and rapid change of momentum (velocity and direction) of the entering fluid stream. This, along with the difference in densities of the liquid and gas, causes fluids separation.

Inlet Divertor

Wave Breakers
In long horizontal separators, waves may develop at the gas–liquid interface. This creates unsteady fluctuations in the liquid level and would negatively affect the performance of the liquid level controller. To avoid this, wave breakers, which consist of vertical baffles installed perpendicular to the flow direction, are used.

Defoaming Plates
Depending on the type of oil and presence of impurities, foam may form at the gas–liquid interface. This results in the following serious operational problems:
1. Foam will occupy a large space in the separator that otherwise would be available for the separation process; therefore, the separator efficiency will be reduced unless the separator is oversized to allow for the presence of foam.
2. The foam, having a density between that of the liquid and gas, will disrupt the operation of the level controller.
3. If the volume of the foam grows, it will be entrained in the gas and liquid streams exiting the separator; thus, the separation process will be ineffective. The entrainment of liquid with the exiting gas is known as liquid carryover. Liquid carryover could also occur as a result of a normally high liquid level, a plugged liquid outlet, or an undersized separator with regard to liquid capacity. The entrainment of gas in the exiting liquid is known as gas blowby. This could also occur as a result of a normally low liquid level, an undersized separator with regard to gas capacity,
or formation of a vortex at the liquid outlet.
Foaming problems may be effectively alleviated by the installation of defoaming plates within the separator. Defoaming plates are basically a series of inclined closely spaced parallel plates. The flow of the foam through such plates results in the coalescence of bubbles and separation of the liquid from the gas.
In some situations, special chemicals known as foam depressants may be added to the fluid mixture to solve foaming problems. The cost of such chemicals could, however, become prohibitive when handling high production rates.

Separator

Vortex Breaker
A vortex breaker, similar in shape to those used in bathroom sink drains, is normally installed on the liquid outlet to prevent formation of a vortex when the liquid outlet valve is open. The formation of a vortex at the liquid outlet may result in withdrawal and entrainment of gas with the exiting liquid (gas blowby).

Sand Jets and Drains
As explained previously , formation sand may be produced with the fluids. Some of this sand will settle and accumulate at the bottom of the separator. This takes up separator volume and disrupts the efficiency of
separation. In such cases, vertical separators will be preferred over horizontal separators. However, when horizontal separators are needed, the separator should be equipped with sand jets and drains along the bottom of the separator. Normally, produced water is injected though the jets to fluidize the accumulated sand, which is then removed through the drains.

Design Principles and Sizing of Gas–Oil Separators
In this section, some basic assumptions and fundamentals used in sizing gas–oil separators are presented first. Next, the equations used for designing vertical and horizontal separators are derived. This will imply finding the diameter and length of a separator for given conditions of oil and gas flow rates, or vice versa.

Assumptions
1. No oil foaming takes place during the gas–oil separation (otherwise retention time has to be drastically increased as explained earlier).
2. The cloud point of the oil and the hydrate point of the gas are below the operating temperature.
3. The smallest separable liquid drops are spherical ones having a diameter of 100 mm.
4. Liquid carryover with the separated gas does not exceed 0.10 gallon/MMSCF (M¼1000).

Fundamentals
1. The difference in densities between liquid and gas is taken as a basis for sizing the gas capacity of the separator .
2. A normal liquid (oil) retention time for gas to separate from oil is between 30 s and 3 min. Under foaming conditions, more time is considered (5–20 min). Retention time is known also as the residence time (¼V/Q, where V is the volume of vessel occupied by oil and Q is the liquid flow rate).
3. In the gravity settling section, liquid drops will settle at a terminal velocity that is reached when the gravity force Fg acting on the oil drop balances the drag force (Fd) exerted by the surrounding fluid or gas.
4. For vertical separators, liquid droplets (oil) separate by settling downward against an up-flowing gas stream; for horizontal ones, liquid droplets assume a trajectory like path while it flows through the vessel (the trajectory of a bullet fired from a gun).
5. For vertical separators, the gas capacity is proportional to the cross-sectional area of the separator, whereas for
horizontal separators, gas capacity is proportional to area of disengagement (LD) (i.e., length  diameter).

Settling of Oil Droplets
In separating oil droplets from the gas in the gravity settling section of a separator, a relative motion exists between the particle, which is the oil droplet, and the surrounding fluid, which is the gas. An oil droplet, being much greater in density than the gas, tends to move vertically downward under the gravitational or buoyant force, Fg.
The fluid (gas), on the other hand, exerts a drag force, Fd, on the oil droplet in the opposite direction. The oil droplet will accelerate until the frictional resistance of the fluid drag force, Fd, approaches and balances Fg; and, thereafter, the oil droplet continues to fall at a constant velocity known as the settling or terminal velocity.

read also:
 Gas – Oil Separators Part.1
2-phase Gas Oil Separation

References:
1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook. 

Gas–Oil Separators part. 1


Commercial Types of Gas–Oil Separator

Based on the configuration, the most common types of separator are horizontal, vertical, and spherical, Large horizontal gas–oil separators are used almost exclusively in processing well fluids in the Middle East, where the gas–oil ratio of the producing fields is high. Multistage GOSPs normally consists of three or more separators.

The following is a brief description of some separators for some specific applications. In addition, the features of what is known as ‘‘modern’’ GOSP are highlighted.

GOSP

Test Separators

These units are used to separate and measure at the same time the well fluids. Potential test is one of the recognized tests for measuring the quantity of both oil and gas produced by the well in 24 hours period under
steady state of operating conditions. The oil produced is measured by a flow meter (normally a turbine meter) at the separator’s liquid outlet and the cumulative oil production is measured in the receiving tanks.

An orifice meter at the separator’s gas outlet measures the produced gas. Physical properties of the oil and GOR are also determined. Equipment for test units.

Modern GOSPs
Safe and environmentally acceptable handling of crude oils is assured by treating the produced crude in the GOSP and related crude-processing facilities. The number one function of the GOSP is to separate the associated gas from oil. As the water content of the produced crude increases, field facilities for control or elimination of water are to be
added. This identifies the second function of a GOSP. If the effect of corrosion due to high salt content in the crude is recognized, then modern desalting equipment could be included as a third function in the GOSP design.

horizontal separator internal design
Horizontal Separator

One has to differentiate between ‘‘dry’’ crude and ‘‘wet’’ crude. The former is produced with no water, whereas the latter comes along with water. The water produced with the crude is a brine solution containing salts (mainly sodium chloride) in varying concentrations.
The input of wet crude oil into a modern GOSP consists of the following:

 

 

1. Crude oil.
2. Hydrocarbon gases.
3. Free water dispersed in oil as relatively large droplets, which will separate and settle out rapidly when wet crude is retained in the vessel.
4. Emulsified water, dispersed in oil as very small droplets that do not settle out with time. Each of these droplets is surrounded by a thin film and held in suspension.
5. Salts dissolved in both free water and in emulsified water.

التصميم الداخلي لعازلة أفقية
vertical separator internal design

The functions of a modern GOSP could be summarized as follows:
1. Separate the hydrocarbon gases from crude oil.
2. Remove water from crude oil.
3. Reduce the salt content to the acceptable level [basic sediments and water]
It should be pointed out that some GOSPs do have gas compression and refrigeration facilities to treat the gas before sending it to gas processing plants. In general, a GOSP can function according to one of the following process operation:
1. Three-phase, gas–oil–water separation .
2. Two-phase, gas–oil separation
3. Two-phase, oil–water separation
4. Deemulsification
5. Washing
6. Electrostatic coalescence
To conclude, the ultimate result in operating a modern three-phase separation plant is to change ‘‘wet’’ crude input into the desired outputs.

 

Controllers and Internal Components of Gas–Oil Separators

Gas–oil separators are generally equipped with the following control devices and internal components.

Liquid Level Controller
The liquid level controller (LLC) is used to maintain the liquid level inside the separator at a fixed height. In simple terms, it consists of a float that exists at the liquid–gas interface and sends a signal to an automatic diaphragm motor valve on the oil outlet. The signal causes the valve to open or close, thus allowing more or less liquid out of the separator to maintain its level inside the separator.

Pressure Control Valve
The pressure control valve (PCV) is an automatic backpressure valve that exists on the gas stream outlet. The valve is set at a prescribed pressure. It will automatically open or close, allowing more or less gas to flow out of the separator to maintain a fixed pressure inside the separator.

Pressure Relief Valve
The pressure relief valve (PRV) is a safety device that will automatically open to vent the separator if the pressure inside the separator exceeded the design safe limit.

Mist Extractor

The function of the mist extractor is to remove the very fine liquid droplets from the gas before it exits the separator. Several types of mist extractors are available:

mist extractor mist extractor

1. Wire-Mesh Mist Extractor
: These are made of finely woven stainless-steel wire wrapped into a tightly packed cylinder of about 6 in. thickness. The liquid droplets that did not separate in the gravity settling section of the separator coalesce on the surface of the matted wire, allowing liquid-free gas to exit the separator. As the droplets size grows, they fall down into the liquid phase. Provided that the gas velocity is reasonably low, wire-mesh extractors are capable of removing about 99% of the 10-mm and larger liquid droplets. It should be noted that this
type of mist extractor is prone to plugging. Plugging could be due to the deposition of paraffin or the entrainment of large liquid droplets in the gas passing through the mist extractor (this will occur if the separator was not properly designed). In such cases, the vane-type mist extractor, described next, should be used.

2. Vane Mist Extractor: This type of extractor consists of a series of closely spaced parallel, corrugated plates. As the gas and entrained liquid droplets flowing between the plates change flow direction, due to corrugations, the liquid droplets impinge on the surface of the plates, where they coalesce and fall down into the liquid collection section.

3. Centrifugal Mist Extractor: This type of extractor uses centrifugal force to separate the liquid droplets from the gas.
Although it is more efficient and less susceptible to plugging than other extractors, it is not commonly used because of its performance sensitivity to small changes in flow rate.

read also:
 Gas – Oil Separators Part.2
2-phase Gas Oil Separation

References:
1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook.

Two-Phase Gas–Oil Separation

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.

Vertical SeparatorIn 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 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).

When, on the other hand, salt water is produced with the oil, it is then essential to use three-phase separators, oil-field separators can be classified into two types based on the number of phases to separate:
1. Two-phase separators, which are used to separate gas from oil in oil fields, or gas from water for gas fields.
2. Three-phase separators, which are used to separate the gas from the liquid phase, and water from oil.
Oil from each producing well is conveyed from the wellhead to a gathering center through a flow line. The gathering center, usually located in some central location within the field, will handle the production from several wells in order to process the produced oil–gas mixture.
Separation of the oil phase and the gas phase enables the handling, metering, and processing of each phase independently, hence producing marketable products.

THEORY OF GAS–OIL SEPARATION

Propane
Propane

In order to understand the theory underlying the separation of well effluent hydrocarbon mixtures into a gas stream and oil product, it is assumed that such mixtures contain essentially three main groups of hydrocarbon,
1. Light group, which consists of CH4 (methane) and C2H6 (ethane)
2. Intermediate group, which consists of two subgroups: the propane/butane (C3H8/C4H10) group and the pentane/hexane (C5H12/C6H14) group.
3. Heavy group, which is the bulk of crude oil and is identified as C7H16.
In carrying out the gas–oil separation process, the main target is to try to achieve the following objectives:
1. Separate the C1 and C2 light gases from oil
2. Maximize the recovery of heavy components of the intermediate group in crude oil
3. Save the heavy group components in liquid product To accomplish these objectives, some hydrocarbons of the
intermediate group are unavoidably lost in the gas stream. In order to minimize this loss and maximize liquid recovery, two methods for the mechanics of separation are compared:
1. Differential or enhanced separation
2. Flash or equilibrium separation
In differential separation, light gases (light group) are gradually and almost completely separated from oil in a series of stages, as the total pressure on the well-effluent mixture is reduced. Differential separation is characterized by the fact that light gases are separated as soon as they are liberated (due to reduction in pressure). In other words, light components do not come into contact with heavier hydrocarbons; instead, they find their way out.
For flash separation, on the other hand, gases liberated from the oil are kept in intimate contact with the liquid phase. As a result, thermodynamic equilibrium is established between the two phases and separation takes place at the required pressure.
Comparing the two methods, one finds that in differential separation, the yield of heavy hydrocarbons (intermediate and heavy groups) is maximized and oil-volume shrinkage experienced by crude oil in the storage tank is minimized. This could be explained by the fact that separation of most of the light gases take place at the earlier high-pressure
stages; hence, the opportunity of loosing heavy components with the light gases in low-pressure stages is greatly minimized. As a result, it may be concluded that flash separation is inferior to differential separation because the former experiences greater losses of heavy hydrocarbons that are carried away with the light gases due to equilibrium conditions.
Nevertheless, commercial separation based on the differential concept is very costly and is not a practical approach because of the many stages required. This would rule out differential separation, leaving the flash process as the only viable scheme to affect gas–oil separation using a small number of stages, a close approach to
differential separation is reached by using four to five flash separation stages.

GAS–OIL SEPARATION EQUIPMENT
The conventional separator is the very first vessel through which the welleffluent mixture flows. In some special cases, other equipment (heaters, water knockout drums) may be installed upstream of the separator.
The essential characteristics of the conventional separator are the following:
1. It causes a decrease in the flow velocity, permitting separation of gas and liquid by gravity.
2. It always operates at a temperature above the hydrate point of the flowing gas.
The choice of a separator for the processing of gas–oil mixtures containing water or without water under a given operating conditions and for a specific application normally takes place guided by the general classification.

Functional Components of a Gas–Oil Separator

Regardless of their configuration, gas–oil separators usually consist of four functional sections:
1. Section A: Initial bulk separation of oil and gas takes place in this section. The entering fluid mixture hits the inlet diverter.
This causes a sudden change in momentum and, due to the gravity difference, results in bulk separation of the gas from the oil. The gas then flows through the top part of the separator and the oil through the lower part.
2. Section B: Gravity settling and separation is accomplished in this section of the separator. Because of the substantial reduction in gas velocity and the density difference, oil droplets settle and separate from the gas.
3. Section C: Known as the mist extraction section, it is capable of removing the very fine oil droplets which did not settle in the gravity settling section from the gas stream.
4. Section D: This is known as the liquid sump or liquid collection section. Its main function is collecting the oil and retaining it for a sufficient time to reach equilibrium with the gas before it is discharged from the separator.

In separating the gas from oil, a mechanical mechanism could be suggested which implies the following two
steps:

(a) To separate oil from gas: Here, we are concerned primarily with recovering as much oil as we can from the gas stream. Density difference or gravity differential is responsible for this separation. At the separator’s operating condition of high pressure, this difference in density between oil and gas becomes small (gas law). Oil is about eight times as dense as the gas. This could be a sufficient driving force for the liquid particles to separate and settle down. This is especially true for large-sized particles, having diameter of 100 mm or more. For smaller ones,
mist extractors are needed.

(b) To remove gas from oil: The objective here is to recover and collect any non solution gas that may be entrained or ‘‘locked’’ in the oil. Recommended methods to achieve this are settling, agitation, and applying heat and chemicals.

read also:
Gas – Oil Separators part. 1
 Gas – Oil Separators Part.2

References:
1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook.

Oil Refinery Processes

Process Objective:
To distill and separate valuable distillates (naphtha, kerosene,diesel) and atmospheric gas oil (AGO) from the crude feedstock.

Refinery

Primary Process Technique:
Complex distillation

Process steps:
–Preheat the crude feed utilizing recovered heat from the product streams
–Desalt and dehydrate the crude using electrostatic enhanced liquid/liquid separation (Desalter)
–Heat the crude to the desired temperature using fired heaters
–Flash the crude in the atmospheric distillation column
–Utilize pumparoundcooling loops to create internal liquid reflux
–Product draws are on the top, sides, and bottom.

Typical Yields and Dispositions:

product & Yield in wt% of Crude

Light Ends 2.3
Light Naphtha  6.3
Medium Naphtha 14.4
Heavy Naphtha 9.4
Kerosene  9.9
Atmospheric Gas Oil 15.1
Reduced Crude 42.6

Vacuum Distillation Unit VDU Process
Process Objective:
To recover valuable gas oils from reduced crude via vacuum distillation.
Primary Process Technique:
Reduce the hydrocarbon partial pressure via vacuum and stripping steam.
Process steps:
–Heat the reduced crude to the desired temperature using fired heaters
–Flash the reduced crude in the vacuum distillation column
–Utilize pumparoundcooling loops to create internal liquid reflux
–Product draws are top, sides, and bottom.

Vacuum Distillation Unit (VDU) Process Schematic

Vacuum-Distillation-Unit

Typical Yields and Dispositions:

product & Yield in wt% of Crude

Light Ends <1
Light VGO 17.6
Heavy VGO 12.7
Vacuum residue (Resid) 12.3

Delayed Coking Process:

Process Objective:
To convert low value residto valuable products (naphtha and diesel) and cokergas oil.
Primary Process Technique:
Thermo cracking increases H/C ratio by carbon rejection in a semi-batch process.
Process steps:
–Preheat residfeed and provide primary condensing of coke drum vapors by introducing the feed to the bottom of the main fractionator
–Heat the coke drum feed by fired heaters
–Flash superheated feed in a large coke drum where the coke remains and vapors leave the top and goes back to the fractionator
–Off-line coke drum is drilled and the petroleum coke is removed via hydrojetting.

Delayed Coking Process Schematic

Delayed Coking process

Fluidic Coking Process

Process Objective:
–To convert low value residto valuable products (naphtha and diesel) and coker gas oil.
Primary Process Technique:
–Thermocracking increases H/C ratio by carbon rejection in a continuous process.
Process steps:
–Preheat residfeed, scrub coke particles, and provide primary condensing of reactor vapors by introducing the feed to the scrubber
–Residis atomized into a fluid coke bed and thermocracking occurs on the particle surface
–Coke particles leaving the reactor are steam stripped to remove remaining liquid hydrocarbons
–Substoichiometricair is introduced to burner to burn some of the coke and provide the necessary heat for the reactor
–Reactor vapors leave the scrubber and go to the fractionator.

Delayed & Fluid Coking Processes
Typical Yields and Dispositions

Light Ends 12.5 –20
Naphtha 10 –15
Light Coker Gas Oil 18 –24
Heavy Coker Gas Oil 30 –40
Pet. Coke 20 -35

 Fluidic Catalytic Cracking FCC Process

Process Objective:
–To convert low value gas oils to valuable products (naphtha and diesel) and slurry oil.
Primary Process Technique:
–Catalytic cracking increases H/C ratio by carbon rejection in a continuous process.
Process steps:
–Gas oil feed is dispersed into the bottom of the riser using steam
–Thermal cracking occurs on the surface of the catalyst
–Disengaging drum separates spent catalyst from product vapors
–Steam strips residue hydrocarbons from spent catalyst
–Air burns away the carbon film from the catalyst in either a “partial-burn”or “full-burn”mode of operation
–Regenerated catalyst enters bottom of riser-reactor.

 Fluid-Catalytic-Cracking

Typical Yields and Dispositions:

Light Ends 16.5 – 22
Naphtha 44 – 56
Light Cycle Oil  13 – 20
Medium Cycle Oil 10 – 26
Slurry Oil 4 – 12
Coke 5 – 6

 HF Alkylation Process

Process Objective:
–To combine light olefins (propylene and butylene) with isobutaneto form a high octane gasoline (alkylate).
Primary Process Technique:
–Alkylationoccurs in the presence of a highly acidic catalyst (hydroflouricacid or sulfuric acid).
Process steps:
–Olefins from FCC are combined with IsoButaneand fed to the HF Reactor where alkylation occurs
–Acid settler separates the free HF from the hydrocarbons and recycles the acid back to the reactor
–A portion of the HF is regenerated to remove acid oils formed byfeed contaminants or hydrocarbon polymerization
–Hydrocarbons from settler go to the DeIsobutanizerfor fractionating the propane and isobutane from the n-butane and alkylate
–Propane is then fractionated from the isobutane; propane as a product and the isobutaneto be recycled to the reactor
–N-Butane and alkylateare deflourinatedin a bed of solid adsorbent and fractionated as separate products.

Hydrotreating Process

Naphtha Hydrotreating
–Primary objective is to remove sulfur contaminant for downstream processes; typically < 1 wppm
Gasoline Hydrotreating
–Sulfur removal from gasoline blending components to meet recent clean fuels specifications
Mid-Distillate Hydrotreating
–Sulfur removal from kerosene for home heating
–Convert kerosene to jet via mild aromatic saturation
–Remove sulfur from diesel for clean fuels
Ultra-low sulfur diesel requirements are leading to major unit revamps
FCC Feed Pretreating
–Nitrogen removal for better FCC catalyst activity
–Sulfur removal for SOx reduction in the flue gas and easier post-FCC treatment
–Aromatic saturation improves FCC feed “crackability”
–Improved H/C ratios increase FCC capacity and conversion.

Hydrocracking Process
Process Objective:
–To remove feed contaminants (nitrogen, sulfur, metals) and to convert low value gas oils to valuable products (naphtha, middle distillates, and ultra-clean lube base stocks).
Primary Process Technique:
–Hydrogenation occurs in fixed hydrotreating catalyst beds to improve H/C ratios and to remove sulfur, nitrogen, and metals. This is followed byone or more reactors with fixed hydrocracking catalyst beds to dealkylatearomatic rings, open naphthenerings, and hydrocrack paraffin chains.
Process steps:
–Preheated feed is mixed with hot hydrogen and passes through a multi-bed reactor with interstagehydrogen quenches for hydrotreating
–Hydrotreatedfeed is mixed with additional hot hydrogen and passes through amulti-bed reactor with quenches for first pass hydrocracking
–Reactor effluents are combined and pass through high and low pressure separators and are fed to the fractionatorwhere valuable products are drawn from the top, sides, and bottom
–Fractionator bottoms may be recycled to a second pass hydrocrackerfor additional conversion all the way up to full conversion.

Rerfrences:
1. Fundamentals of Oil Refining.
2. Oil Refinery Processes

Drilling Rotating Equipment

Drilling Rotating EquipmentRotating system:
the figure indicate the comparative sizes of the drill pipe and drill collar.

Swivel

♦ The swivel hangs from the drilling hook by means of large bail, or handle. The swivel is not rotate, but allow everything below it to rotate.

♦ Drilling fluid is introduced into the drillstem through a gooseneck connection on the swivel, which is connected to the rotary hose.

Power Swivel

♦ When a ‘top-drive’ system is used, the swivel is replace by power swivel.

♦ The power swivel performs the same functions as the ‘normal swivel’, but it is also associated with a transmission system used to rotate the drill string, instead of the rotary table transmitting this motion.

Read also Testing of Drilling Systems

Kelly

♦ The kelly is approximatel 40 feet long, square or hexagonal on the outside and hollow throughout to provide a passage way for the drilling fluid.

♦ Its outer surfaces engages corresponding square or hexagonal surfaces in the kelly bushing.

♦ The kelly bushing fits into a part of rotary table called master bushing. Powered gears in the rotary table rotate the master bushing, and thus the kelly bushing.

♦ The kelly bushing will rotate the kelly and everything below it to rotate.

Drill String

♦ The drillstring is made up of the drillpipe, drill collars, and specialized subs through which the drilling fluid and rotational power are transmitted from the surface to the bit.

♦ Drill pipe and drill collar come in sections, or joints, about 30 feet long.

♦ The most commonly used diameters of drill pipe are 4, 4½, and 5 inches OD.

♦ The purpose of drill collars is to put extra weight on he bit, so they are usually larger in diameter than drill pipe and have thicker walls.

Rotating Equipment: Drill String

♦ Drill pipe and drill collars have threaded connection on each end.

♦ On drill pipe the threaded connection are called tool joints. Tool joints are steel rings that are welded to each end of a joint of drill pipe. One tool joints is a pin (male) connection, and the other is a box (female) connection.

♦ Specialized Subs: The word “sub” refers to any short length of pipe, collar, casing, etc., with a definite function.

Drill Bit

Read a full article about Drilling Bits

♦ At the bottom of drillstring is a the bit, which drills the formation rock.

♦ Most common types are roller cone bits and diamond bits.

♦ The bit size: range from 3¾ inches (9.5 cm) to 26 inches (66 cm) in diameters. The most commonly used sizes are 17½, 12¼, 77/8, and 6 ¼ inches (44, 31, 20, and 16 cm).

♦ Roller cone bits usually have three cone-shaped steel devices that are free to turn as the bit rotates.

♦ Several rows of teeth, or cutters, on each cone scrape, gouge, or crush the formation as the teeth roll over it.

♦ Two types: milled teeth and tungsten carbide inserts.

♦ Most roller cone bits are jet bits: drilling fluid exits from the bit through nozzles between the cone, thus create high velocity jets of mud. This will help lift cuttings away from the bit.

Circulating System
There are a number of main objectives of this system:

♦ Cooling and lubricating the drill bit.

♦ Controlling well pressure.

♦ Removing debris and cuttings.

♦ Coating the walls of the well with a mud cake.

– The circulating system consists of drilling fluid, which is circulated down through the well hole.

– The most common liquid drilling fluid, known as ‘mud’, may contain clay, chemicals, weighting materials, water
and oil.

– The circulating system consists of a starting point, the mud pit, where the drilling fluid ingredients are stored.

 – Mixing takes place at the mud mixing hopper, from which the fluid is forced through pumps up to the swivel and down all the way through the drill pipe, emerging through the drill bit itself.

– From there, the drilling fluid circulates through the bit, picking up debris and drill cuttings, to be circulated back up the well, traveling between the drill string and the walls of the well (also called the ‘annular space’).

– Once reaching the surface, the drilling fluid is filtered to recover the reusable fluid.

Drilling Circulating System

Detection of Oil Spills

Oil Spills

oil spillSpecial instruments are sometimes required to detect an oil spill, especially if the slick is very thin or not clearly visible. For example, if a spill occurs at night, in ice, or among weeds, the oil slick must be detected and tracked using instruments onboard aircraft, satellites, or spacecraft. This technology is known as remote sensing.
There are also surface technologies available to detect and track oil slicks. In addition, samples of the oil must often be obtained and analyzed to determine the oil’s properties, its degree of weathering, its source, or its potential impact on the environment. This analysis, as well as tracking and remote sensing technologies, are
discussed in this article.

In the past, when an oil spill occurred, the location and extent of the spill, the potential behaviour of the oil, and its impact on the environment were often not immediately known. Today, technology is available to provide much of this information.
Laboratory analysis can provide information to help identify an oil if its source is unknown and a sample is available. With a sample of the source oil, the degree of weathering and the amount of evaporation or biodegradation can be determined for the spilled oil. Through laboratory analysis, the more-toxic compounds in the oil can be measured and the relative toxicity of the oil at various stages of the spill can be determined. This is valuable information to have as the spill progresses.

SAMPLING AND LABORATORY ANALYSIS
Taking a sample of oil and then transporting it to a laboratory for subsequent analysis is common practice. While there are many procedures for taking oil samples, it is always important to ensure that the oil is not tainted from contact with other materials and that the sample bottles are pre-cleaned with solvents, such as hexane,
that are suitable for the oil.
The simplest and most common form of analysis is to measure how much oil is in a water, soil, or sediment sample. Such analysis results in a value known as total petroleum hydrocarbons (TPH). The TPH measurement can be obtained in many ways, including extracting the soil, or evaporating a solvent such as hexane and measuring the weight of the residue that is presumed to be oil.
The oil can also be extracted from water using an oil-absorbing and waterrepelling solid. The oil is then analyzed from this substrate by a variety of means, including measuring the amount of light absorbed in certain selected narrow bands.
Still another method is to use enzymes that are selectively affected by some of the oil’s components. A test kit that uses colour to indicate the effect of the oil on the enzymes is available.
A more sophisticated form of analysis is to use a gas chromatograph (GC). A small sample of the oil extract, often in hexane, and a carrier gas, usually helium, are passed through a small glass capillary. The glass column is coated with absorbing materials and, as the various components of the oil have varying rates of adhesion, the oil separates as these components are absorbed at different rates onto the column walls. The gases then pass through a sensitive detector. The system is calibrated by passing known amounts of standard materials through the unit. The amount of many individual components in the oil is thereby measured. The components that pass through the detector can also be totalled and a TPH value determined. While it is highly accurate, this value does not include resins, asphaltenes, and some other components of the oil with higher molecular weight that do not pass through the
column.

One type of detector used on a gas chromatogram is a mass spectrometer (MS). The method is usually called GC-MS and can be used to quantify and identify many components in oil. The mass spectrometer provides information about the structure of the substance so that each peak in the chromatogram can be more positively identified. This information can then be used to predict how long the oil has been in the environment and what percentage of it has evaporated or biodegraded. This is possible because some of the components in oils, particularly crude oils, are very
resistant to biodegradation, while others are resistant to evaporation. This difference in the distribution of components then allows the degree of weathering of the oil to be measured. The same technique can be used to “fingerprint” an oil and positively identify its source. Certain compounds are consistently distributed in oil, regardless
of weathering, and these are used to identify the specific type of oil.

FIELD ANALYSIS
Analysis performed in the field is faster and more economical than analysis done in a laboratory. As analytical techniques are constantly improving and lighter and more portable equipment is being developed, more analytical work can be carried out directly in the field. Test methods are now available for measuring physical properties of oil such as viscosity, density, and even flash point in the field. Test kits have also been developed that can measure total petroleum hydrocarbons directly in the field. While these test kits are less accurate than laboratory methods, they are a rapid screening tool that minimizes laboratory analysis and may provide adequate data for making response decisions.
DETECTION AND SURVEILLANCE
Oil Spill Detection and Tracking Buoys and Systems
As oil spills frequently occur at moorings and docks, buoys and fixed-point monitoring systems have been developed to ensure rapid response at these sites.
These systems detect the oil on water and transmit a radio signal to an oil spill response agency.

Fluorescence
is one method used to detect oil in these systems. An ultraviolet light is focused on the water surface and any oil that is present fluoresces, or absorbs the ultraviolet light and re-emits it as visible light. This fluorescing phenomenon is relatively unique to oil and provides a positive detection mechanism.

In another detection method, an oil sorbent is used that changes in physical properties when it absorbs oil and thus triggers a device. An example of this would be a sorbent that loses it strength when oil is absorbed. The sorbent is placed in contact with a spring and a switch, which is activated when oil enters the sorbent.
This type of device is not effective for fast response. Other detection units are triggered by the differential light reflection or absorption properties of oil.As these systems monitor a specific small area of water, they must be located where a spill would be likely to enter that area. It is difficult to determine this entry point in most situations. Furthermore, technologies available today are not sensitive to quantities of oil released and thus may be triggered by very small amounts of oil. For these reasons, these systems are not used extensively.

As an oil spill moves with the winds and surface currents, the slick or portions of it may move and responders may not always know its position, especially in darkness or fog. Buoys have been developed that move on the water in a manner similar to oil. These buoys transmit a position signal directly to receivers located on aircraft or ships or to a satellite that corresponds to the position of the oil slick.
Some of these buoys receive Global Positioning System (GPS) data from satellites and transmit this with the signal. The position of the spill can then be determined using a remote receiver. For this type of device to be effective, however, the buoy must respond to both the wind and surface currents in the same way as the oil would.
Although this precision in response is difficult to achieve, devices are available that can successfully track a range of crude oils and Bunker C.

Visual Surveillance
Oil spills are often located and surveyed from helicopters or aircraft using only human vision. There are some conditions, however, such as fog and darkness, in which oil on the surface cannot be seen. Very thin oil sheens are also difficult to detect as is oil viewed from an oblique angle (less than 45°) especially in misty or other conditions that limit vision. Oil can also be difficult to see in high seas and among debris or weeds and it can blend into dark backgrounds, such as water, soil,
or shorelines. Oil spill

In addition, many naturally occurring substances or phenomena can be mistaken for oil. These include weeds and sunken kelp beds, whale and fish sperm, biogenic or natural oils such as from plants, glacial flour (finely ground mineral material, usually from glaciers), sea spume (organic material), wave shadows, sun glint and wind sheens on water, and oceanic and riverine fronts where two different bodies of water meet, such as a river entering another body of water.
A very thin oil sheen as it appears on water is shown in the above Figure. This figure also shows the thickness and amount of oil that could be present under such circumstances.
REMOTE SENSING
Remote sensing of oil involves the use of sensors other than human vision to detect or map oil spills. As already noted, oil often cannot be detected in certain conditions. Remote sensing provides a timely means to map out the locations and approximate concentrations of very large spills in many conditions. Remote sensing is usually carried out with instruments onboard aircraft or by satellite. While many sensors have been developed for a variety of environmental applications, only a few are useful for oil spill work. Remote sensing of oil on land is particularly limited and only one or two sensors are useful.

Visual and Ultraviolet Sensors
Many devices employing the visible spectrum, including the conventional video camera, are available at a reasonable cost. As these devices are subject to the same interferences as visual surveillance, they are used primarily to document the spill or to provide a frame of reference for other sensors. A sub-set of sensors operating in the ultraviolet spectrum may be useful for mapping out a very thin sheen.

Infrared Sensors
Thick oil on water absorbs infrared radiation from the sun and thus appears in infrared data as hot on a cold ocean surface. Unfortunately, many other false targets such as weeds, biogenic oils, debris, and oceanic and riverine fronts can interfere with oil detection. The advantage of infrared sensors over visual sensors is that they give information about relative thickness since only thicker slicks, probably greater than 100 μ m, show up in the infrared.
Infrared images are sometimes combined with ultraviolet images, which show the thin oil sheens, to yield a relative thickness map of an oil spill. This is referred to as an IR/UV overlay map. Infrared imagery also has some use at night since the oil appears “colder” than the surrounding sea. The oil is not detected at night in the infrared as it is during the day.
Infrared sensors are relatively inexpensive and widely used for supporting cleanup operations and directing cleanup crews to thicker portions of an oil spill.
They are also often used on cleanup vessels. The oblique view from a ship’s mast is often sufficient to provide useful information on where to steer the vessel for best oil recovery over a short range.

Laser Fluorosensors
Oils that contain aromatic compounds will absorb ultraviolet light and give off visible light in response. Since very few other compounds respond in this way, this can be used as a positive method of detecting oil at sea or on land. Laser fluorosensors use a laser in the ultraviolet spectrum to trigger this fluorescing phenomenon and a sensitive light-detection system to provide an oil-specific detection tool. There is also some information in the visible light return that can be used to determine whether the oil is a light or heavy oil or a lubricating oil. Laser fluorosensors are the most powerful remote sensing tools available because they are subject to very few interferences. Laser fluorosensors work equally well on water and on land and are the only reliable means of detecting oil in certain ice and snow situations. Disadvantages include the high cost of these sensors and their large size and weight.
Passive Microwave Sensors The passive microwave sensor detects natural background microwave radiation.
Oil slicks on water absorb some of this signal in proportion to their thickness. While this cannot be used to measure thickness absolutely, it can yield a measure of relative thickness. The advantage of this sensor is that it can detect oil through fog and in darkness. The disadvantages are the poor spatial resolution and relatively
high cost.

Thickness Sensors
Some types of sensors can be used to measure the thickness of an oil slick. For example, the passive microwave sensor can be calibrated to measure the relative thickness of an oil slick. Absolute thickness cannot be measured for the following reasons: many other factors such as atmospheric conditions also change the radiation levels; the signal changes in cyclical fashion with spill thickness; and the signal must be averaged over a relatively wide area and the slick can change throughout this area.
The infrared sensor also measures only relative thickness. Thick oil appears hotter than the surrounding water during daytime. While the degree of brightness of the infrared signal changes little with thickness, some systems have been adjusted to yield two levels of thickness. A third thickness level on the thinner outer edges of fresh slicks shows up “colder” in the infrared as a result of light interference.
Sensors using lasers to send sound waves through oil can measure absolute oil thickness. The time it takes the sound waves to travel through the oil changes little with the type of oil and thus the measurement of this travel time yields a reliable measurement of the oil’s thickness. This type of sensor is large and heavy and is still considered experimental.
Radar
As oil on the sea calms smaller waves (on the order of a few centimetres in length), radar can detect oil on the sea as a calm area. The technique is highly prone to false targets, however, and is limited to a narrow range of wind speeds (approximately 2 to 6 m/s). At winds below this, there are not enough small waves to yield a difference between the oiled area and the sea. At higher winds, the waves can propagate through the oil and the radar may not be able to “see” into the troughs between the waves. Radar is not useful near coastlines or between head lands because the wind “shadows” look like oil. There are also many natural calms on the oceans that can resemble oil. Despite its large size and expense, radar equipment is particularly well suited for searches of large areas and for work at night or in foggy or other bad weather conditions

Satellites
While many satellites provide images in the visible spectrum, oil cannot be seen in these images unless the spill is very large or rare sea conditions are prevalent that provide a contrast to the oil. Oil has no spectral characteristics that allow it to be enhanced from the background.
Several radar satellites are now available that operate in the same manner as airborne radar and share their many limitations. Despite these limitations, radar imagery from satellite is particularly useful for mapping large oil spills. Arrangements to provide the data within a few hours are possible, making this a useful option.

Oil-Base and Synthetic-Base Muds

Drilling Mud Tests

The field tests for rheology, mud density, and gel strength are accomplished in the same manner as outlined for water-based drilling mud. The main difference is that rheology is tested at a specific temperature, usually 120◦F or
150◦F. Because oils tend to thin with temperature, heating fluid is required and should be reported on the API Mud Report.
see our Drilling Fluids Books section

Sand Content
Sand content measurement is the same as for water-base drilling mud except that the mud’s base oil instead of water should be used for dilution. The sand content of oil-base mud is not generally tested.
HPHT Filtration The API filtration test result for oil-base drilling mud is usually zero. In relaxed filtrate oil-based muds, the API filtrate should be all oil. The API test does not indicate downhole filtration rates. The alternative high-temperature–high pressure (HTHP) filtration test will generally give a better indication of the fluid loss characteristics of a fluid under downhole temperatures The instruments for the HTHP filtration test consists essentially of a controlled pressure source, a cell designed towithstand a working pressure of at least 1,000 psi, a system for heating the cell, and a suitable frame to hold the cell and the heating system. For filtration tests at temperatures above 200◦F, a pressurized collection cell is attached to the delivery tube.
The filter cell is equipped with a thermometer well, oil-resistant gaskets, and a support for the filter paper (Whatman no. 50 or the equivalent). A valve on the filtrate delivery tube controls flow from the cell. A nonhazardous
gas such as nitrogen or carbon dioxide should be used as the pressure source. The test is usually performed at a temperature of 220 – 350◦F and a pressure of 500 psi (differential) over a 30-minute period. When other temperatures, pressures, or times are used, their values should be reported together with test results. If the cake compressibility is desired, the test should be repeated with pressures of 200 psi on the filter cell and
100 psi back pressure on the collection cell. The volume of oil collected at the end of the test should be doubled to correct to a surface area of 7.1 inches.

read also Testing of Drilling Systems

Electrical Stability
The electrical stability test indicates the stability of emulsions of water inoilmixtures. The emulsion tester consists of a reliable circuit using a source of variable AC current (or DC current in portable units) connected to strip electrodes . The voltage imposed across the electrodes can be increased until a predetermined amount of current flows through the drilling mud emulsion-breakdown point. Relative stability is indicated as the voltage at the breakdown point and is reported as the electric stability of the fluid on the daily API test report.

Liquids and Solids Content
Oil, water, and solids volume percent is determined by retort analysis as in a water-base drilling mud. More time is required to get a complete distillation of an oil mud than for a water mud. The corrected water phase volume, the volume percent of low-gravity solids, and the oil-to-water ratio can then be calculated.

The volume oil-to-water ratio can be found from the procedure below:

Oil fraction 100 × % by volume oil or synthetic oil / (% by volume oil or synthetic oil−% by volume water)

Chemical analysis procedures for nonaqueous fluids can be found in the API 13B bulletin available from the American Petroleum Institute.

Alkalinity and Lime Content (NAF)
The whole mud alkalinity test procedure is a titration method that measures the volume of standard acid required to react with the alkaline (basic) materials in an oil mud sample.
The alkalinity value is used to calculate the pounds per barrel of unreacted, “excess” lime in an oil mud. Excess alkaline materials, such as lime, help to stabilize the emulsion and neutralize carbon dioxide or hydrogen sulfide
acidic gases.

Total Salinity (Water-Phase Salinity [WAF] for NAF)
The salinity control ofNAFfluids is very important for stabilizing water-sensitive shales and clays. Depending on the ionic concentration of the shale waters and of the drilling mud water phase, an osmotic flow of pure water from the weaker
salt concentration (in shale) to the stronger salt concentration (in mud) will occur. This may cause dehydration of the shale and, consequently, affect its stabilization

Specialized Tests
Other, more advanced laboratory-based testing is commonly carried out on drilling fluids to determine treatments or to define contaminants. Some of the more advanced analytical tests routinely conducted on drilling fluids include:

Advanced Rheology and Suspension Analysis
FANN 50 — A laboratory test for rheology under temperature and moderate pressure (up to 1,000 psi and 500◦F).
FANN 70 — Laboratory test for rheology under high temperature and high pressure (up to 20,000 psi and 500◦F).
FANN 75 — Amore advanced computer-controlled version of the FANN 70 (up to 20,000 psi and 500◦F).

High-Angle Sag Test (HAST)
A laboratory test device to determine the suspension properties of a fluid in high-angle wellbores. This test is designed to evaluate particle setting characteristics of a fluid in deviated wells.

Drilling Mud
Salt Saturation Curves

Dynamic HAST
Laboratory test device to determine the suspension properties of a drilling fluid under high angle and dynamic conditions.

Specialized Filtration Testing
FANN 90 Dynamic filtration testing of a drilling fluid under pressure and temperature. This test determines if the fluid is properly conditioned to drill through highly permeable formations. The test results include two numbers: the dynamic filtration rate and the cake deposition index (CDI).
The dynamic filtration rate is calculated from the slope of the curve of volume versus time. The CDI, which reflects the erodability of the wall cake, is calculated from the slope of the curve of volume/time versus time. CDI and dynamic filtration rates are calculated using data collected after twenty minutes. The filtration media for the FAN 90 is a synthetic core. The core size can be sized for each application to optimize the filtration rate.

Particle-PluggingTest (PPT)
The PPT test is accomplishedwith a modified HPHT cell to examine sealing characteristics of a drilling fluid. The
PPT, sometimes known as the PPA (particle-plugging apparatus), is key when drilling in high-differential-pressure environments.

Aniline Point Test
Determine the aniline point of an oil-based fluid base oil. This test is critical to ensure elastomer compatibility when using nonaqueous fluids.

Particle-Size Distribution (PSD) Test
The PSD examines the volume and particle sizedistribution of solidsinafluid.This test is valuable indetermining
the type and size of solids control equipment that will be needed to properly clean a fluid of undesirable solids.

Luminescence Fingerprinting
This test is used to determine if contamination of a synthetic-based mud has occurredwith crude oil during drilling
operations.

Lubricity Testing
Various lubricity meters and devices are available to the industry to determine how lubricous a fluid is when exposed to steel or shale. In high-angle drilling applications, a highly lubricious fluid is desirable to allow proper transmission of weight to the bit and reduce side wall sticking tendencies.

Geologic Classification of Petroleum Reservoirs

 

Petroleum reservoirs exist in many different sizes and shapes of geologic structures. It is usually convenient to classify the reservoirs according to the conditions of their formation as follows:

A reservoir formed by folding of rock layers.
Figure 1

1. Dome-Shaped and Anticline Reservoirs:

These reservoirs are formed by the folding of the rock layers as shown in Figure 1. The dome is circular in outline, and the anticline is long and narrow. Oil and/or gas moved or migrated upward through the porous strata where it was trapped by the sealing cap rock and the shape of the structure.

 

2. Faulted Reservoirs:

A cross section of a faulted reservoir.
Figure 2

These reservoirs are formed by shearing and offsetting of the strata (faulting), as shown in Figure 2. The movement of the nonporous rock opposite the porous formation containing the oil/gas creates the sealing. The tilt of the petroleum-bearing rock and the faulting trap the oil/gas in the reservoir.

 

 

3. Salt-Dome Reservoirs:

Section in a salt-dome structure
figure 3

This type of reservoir structure, which
takes the shape of a dome, was formed due to the upward
movement of large, impermeable salt dome that deformed and
lifted the overlying layers of rock. As shown in Figure 3,
petroleum is trapped between the cap rock and an underlying
impermeable rock layer, or between two impermeable layers of
rock and the salt dome.

 

 

4. Unconformities:

A reservoir formed by unconformity.
figure 4

This type of reservoir structure, shown in Figure 4, was formed as a result of an unconformity where the
impermeable cap rock was laid down across the cutoff surfaces of the lower beds.

 

 

 

5. Lense-Type Reservoirs:

In this type of reservoir, the petroleum bearing porous formation is sealed by the surrounding, nonporous formation. Irregular deposition of sediments and shale at the time the formation was laid down is the probable cause for this abrupt change in formation porosity.

6. Combination Reservoirs:

In this case, combinations of folding, faulting, abrupt changes in porosity, or other conditions that create the trap, from this common type of reservoir.

Reservoir Drive Mechanisms
At the time oil was forming and accumulating in the reservoir, the pressure energy of the associated gas and water was also stored. When a well is drilled through the reservoir and the pressure in the well is made to be lower than the pressure in the oil formation, it is that energy of the gas, or the water, or both that would displace the oil from the formation into the well and lift it up to the surface. Therefore, another way of classifying petroleum reservoirs,
which is of interest to reservoir and production engineers, is to characterize the reservoir according to the production (drive) mechanism responsible for displacing the oil from the formation into the wellbore and up to the surface. There are three main drive mechanisms:

I. Solution-Gas-Drive Reservoirs:
Depending on the reservoir pressure and temperature, the oil in the reservoir would have varying amounts of gas dissolved within the oil (solution gas).
Solution gas would evolve out of the oil only if the pressure is lowered below a certain value, known as the bubble point pressure, which is a property of the oil. When a well is drilled through the reservoir and the pressure conditions are controlled to create a pressure that is lower than the bubble point pressure, the liberated gas expands and drives the oil out of the formation and assists in lifting it to the surface.
Reservoirs with the energy of the escaping and expanding dissolved gas as the only source of energy are called solution-gas-drive reservoirs.
This drive mechanism is the least effective of all drive mechanisms; it generally yields recoveries between 15% and
25% of the oil in the reservoir.

II. Gas-Cap-Drive Reservoirs:
Many reservoirs have free gas existing as a gas cap above the oil. The formation of this gas cap was due to the presence of a larger amount of gas than could be dissolved in the oil at the pressure and temperature of the reservoir. The excess gas is segregated by gravity to occupy the top portion of the reservoir.
In such a reservoirs, the oil is produced by the expansion of the gas in the gas cap, which pushes the oil downward and fills the pore spaces formerly occupied by the produced oil. In most cases, however, solution gas is also
contributing to the drive of the oil out of the formation.
Under favorable conditions, some of the solution gas may move upward into the gas cap and, thus, enlarge the gas cap and conserves its energy. Reservoirs produced by the expansion of the gas cap are known as Gas-cap-drive
reservoirs. This drive is more efficient than the solution-gas drive and could yield recoveries between 25% and 50% of the original oil in the reservoir.

III. Water-Drive Reservoirs:
Many other reservoirs exist as huge, continuous, porous formations with the oil/gas occupying only a small portion of the formation. In such cases, the vast formation below the oil/gas is saturated with salt water at very high pressure. When oil/gas is produced, by lowering the pressure in the well opposite the petroleum formation, the salt
water expands and moves upward, pushing the oil/gas out of the formation and occupying the pore spaces vacated by the produced oil/gas. The movement of the water to displace the oil/gas retards the decline in oil, or gas pressure, and conserves the expansive energy of the hydrocarbons.
Reservoirs produced by the expansion and movement of the salt water below the oil/gas are known as water-drive
reservoirs. This is the most efficient drive mechanism; it could yield recoveries up to 50% of the original oil.

References:
Petroleum and Natural Gas Field Processing
 -H. K. Abdel-Aal and Mohamed Aggour

Testing of Drilling Systems

drill mudTo properly control the hole cleaning, suspension, and filtration properties of a drilling fluid, testing of the fluid properties is done on a daily basis. Most tests are conducted at the rig site, and procedures are set forth in the API RPB13B. Testing of water-based fluids and nonaqueous fluids can be similar, but variations of procedures occur due to the nature of the fluid being tested.

Water-Base Muds Testing
To accurately determine the physical properties of water-based drilling fluids, examination of the fluid is required in a field laboratory setting. In many cases, this consists of a few simple tests conducted by the derrickman or mud Engineer at the rigsite. The procedures for conducting all routine drilling fluid testing can be found in the American Petroleum Institute’s API RPB13B.

Density Often referred to as themudweight, densitymaybe expressed as pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), specific gravity (SG) or pressure gradient (psi/ft). Any instrument of sufficient accuracy within ±0.1 lb/gal or ±0.5 lb/ft3 may be used. The mud balance is the instrument most commonly used. The weight of a mud cup attached to one end of the beam is balanced on the other end by a fixed counterweight and a rider free to move along a graduated scale. The density of the fluid is a direct reading from the scales located on both sides of the mud balance .
Marsh Funnel Viscosity
Drilling Mud testMud viscosity is a measure of the mud’s resistance to flow. The primary function of drilling fluid viscosity is a to transport cuttings to the surface and suspend weighing materials. Viscosity must be high enough that the weighting material will remain suspended but low enough to permit sand and cuttings to settle out and entrained gas to escape at the surface. Excessive viscosity can create high pump pressure, which magnifies the swab or surge effect during tripping operations. The control of equivalent circulating density (ECD) is always a prime concern when managing the viscosity of a drilling fluid. The Marsh funnel is a rig site instrument used to measure funnel viscosity. The funnel is dimensioned so that by following standard procedures, the outflow time of 1 qt (946 ml) of freshwater at a temperature of 70±5◦F is 26±0.5 seconds. A graduated cup is used as a receiver.

Direct Indicating Viscometer
This is a rotational type instrument powered by an electric motor or by a hand crank . Mud is contained in the annular space between two cylinders. The outer cylinder or rotor sleeve is driven at a constant rotational velocity; its rotation in the mud produces a torque on the inner cylinder or bob. A torsion spring restrains the movement of the bob. A dial attached to the bob indicates its displacement on a direct reading scale. Instrument constraints have been adjusted so that plastic viscosity, apparent viscosity, and yield point are obtained by using readings from rotor sleeve speeds of 300 and 600 rpm.
Plastic viscosity (PV) in centipoise is equal to the 600 rpm dial reading minus the 300 rpm dial reading. Yield point (YP), in pounds per 100 ft2, is equal to the 300-rpm dial reading minus the plastic viscosity. Apparent viscosity in centipoise is equal to the 600-rpm reading, divided by two.

Gel Strength
Gel strength is a measure of the inter-particle forces and indicates the gelling thatwill occur when circulation is stopped. This property prevents the cuttings from setting in the hole. High pump pressure is generally required to “break” circulation in a high-gel mud. Gel strength is measured in units of lbf/100 ft2. This reading is obtained by noting the maximum dial deflection when the rotational viscometer is turned at a low rotor speed (3 rpm) after the mud has remained static for some period of time (10 seconds, 10 minutes, or 30 minutes). If the mud is allowed
to remain static in the viscometer for a period of 10 seconds, the maximum dial deflection obtained when the viscometer is turned on is reported as the initial gel on the API mud report form. If the mud is allowed to remain static for 10 minutes, the maximumdial deflection is reported as the 10-min gel. The same device is used to determine gel strength that is used to determine the plastic viscosity and yield point, the Variable Speed
Rheometer/Viscometer.

API Filtration
A standard API filter press is used to determine the filter cake building characteristics and filtration of a drilling fluid
The API filter press consists of a cylindrical mud chamber made of materials resistant to strongly alkaline solutions. A filter paper is placed on the bottom of the chamber just above a suitable support. The total filtration area is 7.1
(±0.1) in.2. Below the support is a drain tube for discharging the filtrate into a graduated cylinder. The entire assembly is supported by a stand so 100-psi pressure can be applied to the mud sample in the chamber. At the end of the 30-minute filtration time, the volume of filtrate is reported as API filtration in milliliters. To obtain correlative results, one thickness of the proper 9-cm filter paper—Whatman No. 50, S&S No. 5765, or the equivalent—must be
used. Thickness of the filter cake is measured and reported in 32nd of an inch. The cake is visually examined, and its consistency is reported using such notations as “hard,” “soft,” tough,” ’‘rubbery,” or “firm.”

Sand Content
The sand content in drilling fluids is determined using a 200-mesh sand sieve screen 2 inches in diameter, a funnel to fit the screen, and a glass-sand graduated measuring tube . The measuring tube is marked to indicate the volume of “mud to be added,” water to be added and to directly read the volume of sand on the bottom of the tube.
Sand content of the mud is reported in percent by volume. Also reported is thepoint of sampling (e.g., flowline, shale shaker, suctionpit). Solids other than sand may be retained on the screen (e.g., lost circulation material), and
the presence of such solids should be noted.

Liquids and Solids Content
A mud retort is used to determine the liquids and solids content of a drilling fluid. Mud is placed in a steel container and heated at high temperature until the liquid components have been distilled off and vaporized. The vapors are passed through a condenser and collected in a graduated cylinder. The volume of liquids
(water and oil) is then measured. Solids, both suspended and dissolved, are determined by volume as a difference between the mud in container and the distillate in graduated cylinder. Drilling fluid retorts are generally
designed to distill 10-, 20-, or 50-ml sample volumes.

For freshwater muds, a rough measure of the relative amounts of barite and clay in the solids can be made (Table 1.1). Because both suspended and dissolved solids are retained in the retort for muds containing substantial
quantities of salt, corrections must be made for the salt. Relative amounts of high- and low-gravity solids contained in drilling fluids can be found in Table 1.1.

pH
Two methods for measuring the pH of drilling fluid are commonly used: (1) a modified colorimetric method using pH paper or strips and (2) the electrometric method using a glass electrode . The paper strip test may not be reliable if the salt concentration of the sample is high.
The electrometric method is subject to error in solutions containing high concentrations of sodium ions unless a special glass electrode is used or unless suitable correction factors are applied if an ordinary electrode is used. In addition, a temperature correction is required for the electrometric method of measuring pH.
The paper strips used in the colorimetric method are impregnated with dyes so that the color of the test paper depends on the pH of the medium in which the paper is placed. A standard color chart is supplied for comparison
with the test strip. Test papers are available in a wide range, which permits estimating pH to 0.5 units, and in narrow range papers, with which the pH can be estimated to 0.2 units.
The glass electrode pH meter consists of a glass electrode, an electronic amplifier, and a meter calibrated in pH units. The electrode is composed of (1) the glass electrode, a thin-walled bulb made of special glass within
which is sealed a suitable electrolyte and an electrode, and (2) the reference electrode, which is a saturated calomel cell. Electrical connection with the mud is established through a saturated solution of potassium chloride
contained in a tube surrounding the calomel cell. The electrical potential generated in the glass electrode system by the hydrogen ions in the drilling mud is amplified and operates the calibrated pH meter.

Resistivity
Control of the resistivity of the mud and mud filtrate while drilling may be desirable to permit enhanced evaluation of the formation characteristics from electric logs. The determination of resistivity is essentially the measurement of the resistance to electrical current flow through a known sample configuration. Measured resistance is converted to resistivity by use of a cell constant. The cell constant is fixed by the configuration of the sample in the cell and id determined by calibration with standard solutions of known resistivity. The resistivity is expressed in ohm-meters.

Filtrate Chemical Analysis
Standard chemical analyses have been developed for determining the concentration of various ions present in the mud. Tests for the concentration of chloride, hydroxyl, and calcium ions are required to fill out the API drilling mud report. The tests are based on filtration (i.e., reaction of a known volume of mud filtrate sample with a standard solution of known volume and concentration). The end of chemical reaction is usually indicated by the change of color. The concentration of the ion being tested can be determined from a knowledge of the chemical reaction taking place.

Chloride
The chloride concentration is determined by titration with silver nitrate solution. This causes the chloride to be removed from the solution as AgCl−, a white precipitate. The endpoint of the titration is detected using a potassium chromate indicator. The excess Ag present after all Cl− has been removed fromsolution reactswith the chromate to formAg9CrO4, an orange-red precipitate. Contamination with chlorides generally results from drilling salt or from a saltwater flow. Salt can enter and contaminate themudsystem when salt formations are drilled and when saline formation water enters the wellbore.

Alkalinity and Lime Content
Alkalinity is the ability of a solution or mixture to react with an acid. The phenolphthalein alkalinity refers to the
amount of acid required to reduce the pH of the filtrate to 8.3, the phenolphthalein end point. The phenolphthalein alkalinity of the mud and mud filtrate is called the Pm and Pf , respectively. The Pf test includes the effect of only dissolved bases and salts, whereas the Pm test includes the effect of both dissolved and suspended bases and salts. The m and f indicate if the test was conducted on the whole mud or mud filtrate. The Mf alkalinity refers to the amount of acid required to reduce the pH to 4.3, the methyl orange end point. The methyl orange alkalinity of the mud and mud filtrate is called the Mm and Mf , respectively. The API diagnostic tests include the determination of Pm, Pf , and Mf . All values are reported in cubic centimeters of 0.02N (normality= 0.02) sulfuric acid per cubic centimeter of sample. The lime content of the mud is calculated by subtracting the Pf from the Pm and dividing the result by 4.
The Pf and Mf tests are designed to establish the concentration of hydroxyl, bicarbonate, and carbonate ions in the aqueous phase of the mud. At a pH of 8.3, the conversion of hydroxides to water and carbonates to bicarbonates
is essentially complete. The bicarbonates originally present in solution do not enter the reactions. As the pH is further reduced to 4.3, the acid reacts with the bicarbonate ions to form carbon dioxide and water.
ml N/50H2SO4 to reach pH=8.3
CO 3(-2) +H2SO4→HCO3(-) +HSO4
carbonate+acid→bicarbonate+bisulfate
OH−+H2SO4→HOH+SO4=  hydroxyl+acid→water+sulfate salt
The Pf and Pm test results indicate the reserve alkalinity of the suspended solids. As the [OH−] in solution is reduced, the lime and limestone suspended in the mud will go into solution and tend to stabilize the pH
(Table 1.2). This reserve alkalinity generally is expressed as an excess lime concentration, in lb/bbl of mud. The accurate testing of Pf, Mf , and Pm are needed to determine the quality and quantity of alkaline material present
in the drilling fluid. The chart below shows how to determine the hydroxyl, carbonate, and bicarbonate ion concentrations based on these titrations.

Total Hardness
The total combined concentration of calcium and magnesium in the mud-water phase is defined as total hardness. These contaminants are often present in the water available for use in the drilling fluid makeup. In addition, calcium can enter the mud when anhydrite (CaSO4) or gypsum (CaSO4 ·2H2O) formations are drilled. Cement also contains
calcium and can contaminate the mud. The total hardness is determined by titration with a standard (0.02 N) versenate hardness titrating solution (EDTA). The standard versenate solution contains sodium versenate, an
organic compound capable of forming a chelate when combined with Ca2 and Mg2.
The hardness test sometimes is performed on the whole mud as well as the mud filtrate. The mud hardness indicates the amount of calcium suspended in the mud and the amount of calcium in solution. This test usually is made on gypsum-treated muds to indicate the amount of excess CaSO4 present in suspension. To perform the hardness test on mud, a small sample of mud is first diluted to 50 times its original volume with distilled water so that any undissolved calcium or magnesium compounds can go into solution. The mixture then is filtered through hardened filter paper to obtain a clear filtrate. The total hardness of this filtrate then is obtained using the same procedure used for the filtrate from the low-temperature, low-pressure API filter press apparatus.

Methylene Blue Capacity (CEC or MBT)
It is desirable to know the cation exchange capacity (CEC) of the drilling fluid. To some extent, this value can be correlated to the bentonite content of the mud. The test is only qualitative because organic material and other clays present in the mud also absorb methylene blue dye. The mud sample is treated with hydrogen peroxide to oxidize most of the organic material. The cation exchange capacity is reported in milliequivalent weights (mEq) of methylene blue dye per 100 ml of mud. The methylene blue solution used for titration is usually 0.01 N, so that the cation exchange capacity is numerically equal to the cubic centimeters of methylene blue solution per cubic centimeter of sample required to reach an end point. If other adsorptive materials are not present in significant quantities, the montmorillonite content of the mud in pounds per barrel is calculated to be five times the cation exchange capacity.
The methylene blue test can also be used to determine cation exchange capacity of clays and shales. In the test, a weighed amount of clay is dispersed into water by a high-speed stirrer ormixer. Titration is carried out as
for drilling muds, except that hydrogen peroxide is not added. The cation exchange capacity of clays is expressed as milliequivalents of methylene blue per 100 g of clay.

Oil Well Planning

Drilling optimization requires detailed engineering in all aspects of well planning, drilling implementation, and post-run evaluation Effective well planning optimizes the boundaries, constraints, learning, nonproductive time, and limits and uses new technologies as well as tried and true methods. Use of decision support packages, which document the reasoning behind the decision-making, is key to shared learning and continuous improvement processes. It is critical to anticipate potential difficulties, to understand their consequences, and to be prepared with
contingency plans. Post-run evaluation is required to capture learning.
Drilling Planning

Many of the processes used are the same as used during the well planning phase, but are conducted using new data from the recent drilling events. Depending on the phase of planning and whether you are the operator
or a service provider, some constraints will be out of your control to alter or influence (e.g., casing point selection, casing sizes, mud weights, mud types, directional plan, drilling approach such as BHA types or new technology
use). There is significant value inbeing able to identify alternate possibilities for improvement over current methods, but well planning must consider future availability of products and services for possible well interventions.
When presented properly to the groups affected by the change, it is possible to learn why it is not feasible or to alter the plan to cause improvement. Engineers must understand and identify the correct applications for technologies to reduce costs and increase effectiveness.Acorrect application understands the tradeoffs of risk versus rewardandcosts versus benefits.

Boundaries Boundaries are related to the “rules of the game” established by the company or companies involved. Boundaries are criteria established by management as “required outcomes or processes” and may relate to
behaviors, costs, time, safety, and production targets.
Constraints Constraints during drilling may be preplanned trip points for logs, cores, casing, and BHA or bit changes. Equipment, information, human resource knowledge, skills and availability, mud changeover, and dropping balls for downhole tools are examples of constraints on the plan and its implementation.
The Learning Curve Optimization’s progress can be tracked using learning curves that chart the performance measures deemed most effective for the situation and then applying this knowledge to subsequent wells.
Learning curves provide a graphic approach to displaying the outcomes. Incremental learning produces an exponential curve slope. Step changes may be caused by radically new approaches or unexpected trouble. With
understanding and planning, the step change will more likely be in a positive direction, imparting huge savings for this and future wells. The curve slope defines the optimization rate. The learning curve can be used to demonstrate the overall big picture or a small component that affects the overall outcome. In either case, the curve measures the rate of change of the parameter you choose, typically the “performance measures” established by you and your team. Each performance measure is typically plotted against time, perhaps the chronological order of wells drilled as shown in figure below:

Cost Estimating Oneof the mostcommonand critical requests of drilling engineers is to provide accurate cost estimates, or authority for expenditures (AFEs). The key is to use a systematic and repeatable approach that takes
into account all aspects of the client’s objectives. These objectives must be clearly defined throughout the organization before beginning the optimization and estimating process. Accurate estimating is essential to maximizing a company’s resources. Overestimating a project’s cost can tie up capital that could be used elsewhere, and underestimating can create budget shortfalls affecting overall economics.
Integrated Software Packages With the complexity of today’s wells, it is advantageous to use integrated software packages to help design all aspects of the well. Examples of these programs include

• Casing design
• Torque and drag
• Directional planning
• Hydraulics
• Cementing
• Well control
Decision Support Packages Decision support packages document the reasoning behind the decisions that are made, allowing other people to understand the basis for the decisions. When future well requirements change, a decision trail is available that easily identifies when new choices may be needed and beneficial.
Performance Measures Common drilling optimization performance measures are cost per foot of hole drilled, cost per foot per casing interval, trouble time, trouble cost, and AFEs versus actual costs.
Systems Approach Drilling requires the use of many separate pieces of equipment, but they must function as one system. The borehole should be included in the system thinking. The benefit is time reduction, safety improvement, and production increases as the result of less nonproductive time and faster drilling. For example, when an expected average rate of penetration (ROP) and a maximum instantaneous ROP have been identified, it is possible to ensure that the tools and borehole will be able to support that as a plan. Bit capabilities must be matched to the rpm, life, and formation. Downhole motors must provide the desired rpm and power at the flow rate being programmed. Pumps must be able to provide the flow rate and pressure as planned.
Nonproductive Time Preventing trouble events is paramount to achieving cost control and is arguably the most important key to drilling a cost-effective, safe well. Troubles are “flat line” time, a terminology emanating from the days versus depth curve when zero depth is being accomplished for a period of days, creating a horizontal line on the graph. Primary problems invariably cause more serious associated problems. For example, surge pressures can cause lost circulation, which is the most common cause of blowouts. Excessive mud weight can cause differential sticking, stuck pipe, loss of hole, and sidetracking. Wellbore instability can cause catastrophic loss of entire hole sections. Key seating and pipe washouts can cause stuck pipe and a fishing job.
When a trouble event leads to a fishing job, “fishing economics” should be performed. This can help eliminate emotional decisions that lead to overspending. Several factors should be taken into account when determining
whether to continue fishing or whether to start in the first place.
The most important of these are replacement or lost-in-hole cost of tools and equipment, historical success rates (if known), and spread rate cost of daily operations. These can be used to determine a risk-weighted value of
fishing versus the option to sidetrack.
Operational inefficiencies are situations for which better planning and implementation could have saved timeandmoney. Sayings such as“makin’ hole” and “turnin’ to the right” are heard regularly in the drilling business.
These phases relate the concept of maximizing progress. Inefficiencies which hinder progress include
• Poor communications
• No contingency plans and “waiting on orders” (WOO)
• Trips
• Tool failure
• Improper WOB and rpm (magnitude and consistency)
• Mud properties that may unnecessarily reduce ROP (spurt loss, water loss and drilled solids)
• Surface pump capacities, pressure and rate (suboptimum liner selection and too small pumps, pipe, drill collars)
• Poor matching of BHA components (hydraulics, life, rpm, and data acquisition rates)
• Survey time
Limits Each well to be drilled must have a plan. The plan is a baseline expectation for performance (e.g., rotating hours, number of trips, tangibles cost). The baseline can be taken from the learning curves of the best experience that characterizes the well to be drilled. The baseline may be a widely varying estimate for an exploration well or a highly refined measure in a developed field. Optimization requires identifying and improving on the limits that play the largest role in reducing progress for the well being planned. Common limits include
1. Hole Size. Hole size in the range of 7 7/8 – 8 1/2 in. is commonly agreed to be the most efficient and cost-effective hole size to drill, considering numerous criteria, including hole cleaning, rock volume drilled, downhole tool life, bit life, cuttings handling, and drill string handling. Actual hole sizes drilled are typically determined by the size of production tubing required, the required number of casing points, contingency strings, and standard casing decision trees. Company standardization programs for casing, tubing, and bits may limit available choices.
2. Bit Life. Measures of bit life vary depending on bit type and application. Roller cones in soft to medium-soft rock often use KREVs (i.e., total revolutions, stated in thousands of revolutions). This measure fails to consider the effect ofWOBon bearing wear, but soft formations typically use medium to high rpm and low WOB; therefore, this measure has become most common. Roller cones in medium to hard rock often use a multiplication of WOB and total revolutions, referred to as the WR or WN number, depending on bit vender. Roller cone bits smaller than 7 7/8 in. suffer significant reduction in bearing life, tooth life, tooth size, and ROP. PDC bits, impregnated bits, natural diamond bits, and TSP bits typically measure in terms if bit hours and KREVs. Life of all bits is severely reduced by vibration. Erosion can wear bit teeth or the bit face that holds the cutters, effectively reducing bit life.
3. Hole Cleaning. Annular velocity (AV) rules of thumb have been used to suggest hole-cleaning capacity, but each of several factors, including mud properties, rock properties, hole angle, and drill string rotation, must be considered. Directional drilling with steerable systems require “sliding” (not rotating) the drill string during the orienting stage; hole cleaning can suffer drastically at hole angles greater than 50. Hole cleaning in large-diameter holes, even if vertical, is difficult merely because of the fast drilling formations and commonly low AV.
4. Rock Properties. It is fundamental to understand formation type, hardness, and characteristics as they relate to drilling and production. From a drilling perspective, breaking down and transporting rock (i.e., hole cleaning) is required. Drilling mechanics must be matched to the rock mechanics. Bit companies can be supplied with electric logs and associated data so that drill bit types and operating parameters can be recommended that will match the rock mechanics. Facilitating maximum production capacity is given a higher priority through the production zones. This means drilling gage holes,minimizing formation damage (e.g., clean mud, less exposure time), and facilitating effective cement jobs.
5. Weight on Bit. WOB must be sufficient to overcome the rock strength, but excessive WOB reduces life through increased bit cutting structure and bearing wear rate (for roller cone bits). WOB can be expressed in terms of weight per inch of bit diameter. The actual range used depends on the “family” of bit selected and, to some extent, the rpm used. Families are defined as natural diamond, PDC, TSP (thermally stable polycrystalline), impregnated, mill tooth, and insert.
6. Revolutions per Minute (rpm). Certain ranges of rpm have proved to be prudent for bits, tools, drill strings, and the borehole. Faster rpm normally increases ROP, but life of the product or downhole assembly may be severely reduced if rpm is arbitrarily increased too high. A too-low rpm can yield slower than effective ROP and may provide insufficient hole cleaning and hole pack off, especially in high-angle wells.
7. Equivalent Circulating Density (ECD). ECDs become critical when drilling in a soft formation environment where the fracture gradient is not much larger than the pore pressure. Controlling ROP, reducing pumping flow rate, drill pipe OD, and connection OD may all be considered or needed to safely drill the interval.
8. Hydraulic System. The rig equipment (e.g., pumps, liners, engines or motors, drill string, BHA) may be a given. In this case, optimizing the drilling plan based on its available capabilities will be required.
However, if you can demonstrate or predict an improved outcome that would justify any incremental costs, then you will have accomplished additional optimization. The pumps cannot provide their rated horsepower
if the engines providing power to the pumps possess inadequate mechanical horsepower. Engines must be down rated for efficiency.
Changing pump liners is a simple cost-effective way to optimize the hydraulic system. Optimization involves several products and services and the personnel representatives.This increases the difficulty to achieve an optimized parameter selection that is best as a system.

New Technologies

Positive step changes reflected in the learning curve are often the result of effective implementation of new technologies:
1. Underbalanced Drilling. UBD is implemented predominantly to maximize the production capacity variable of the well’s optimization by minimizing formation damage during the drilling process. Operationally, the pressure of the borehole fluid column is reduced to less than the pressure in the ZOI. ROP is also substantially increased. Often,
coiled tubing is used to reduce the tripping and connection time and mitigate safety issues of “snubbing” joints of pipe.
2. Surface Stack Blowout Preventer (BOP). The use of a surface stack BOP configurations in floating drilling is performed by suspending the BOP stack above the waterline and using high-pressure risers (typically 13 3/8 in. casing) as a conduit to the sea floor. This method, generally used in benign and moderate environments, has saved considerable time and money in water depths to 6,000 ft.
3. Expandable Drilling Liners. EDLs can be used for several situations. The casing plan may startwith a smaller diameter than usual, while finishing in the production zone as a large, or larger, final casing diameter. Future advances may allow setting numerous casing strings in succession, all of the exact same internal diameter. The potential as a step change technology for optimizing drilling costs and mitigating risks is phenomenal.
4. Rig Instrumentation. The efficient and effective application of weight to the bit and the control of downhole vibration play a key role in drilling efficiency. Excessive WOB applied can cause axial vibration, causing destructive torsional vibrations. Casing handling systems and top drives are effective tools.
5. Real-Time Drilling Parameter Optimization. Downhole and surface vibration detection equipment allows for immediatemitigation. Knowing actual downhole WOB can provide the necessary information to perform improved drill-off tests .
6. Bit Selection Processes. Most bit venders are able to use the electric log data (Sonic,GammaRay, Resistivity as aminimum)and associated offset information to improve the selection of bit cutting structures. Formation
type, hardness, and characteristics are evaluated and matched to the application needs as an optimization process.

Crude Oil Stabilization and Sweetening

Once degassed and dehydrated–desalted, crude oil is pumped to gathering facilities to be stored in storage tanks. However, if there are any dissolved gases that belong to the light or the intermediate hydrocarbon groups it will be necessary to remove these gases
along with hydrogen sulfide (if present in the crude) before oil can be stored. This process is described as a ‘‘dual process’’ of both stabilizing and sweetening a crude oil.
In stabilization, adjusting the pentanes and lighter fractions retained in the stock tank liquid can change the crude oil gravity. The economic value of the crude oil is accordingly influenced by stabilization. First, liquids can be stored and transported to the market more profitably than gas. Second, it is advantageous to minimize gas losses from light crude oil when stored.
This chapter deals with methods for stabilizing the crude oil to maximize the volume of production as well as its API gravity, against two important constraints imposed by its vapor pressure and the allowable hydrogen sulfide content.
To illustrate the impact of stabilization and sweetening on the quality of crude oil, the properties of oil before and after treatment are compared as follows:
(a) Before treatment
Water content: up to 3% of crude in the form of emulsions and from 3% to 30% of crude as free water
Salt content: 50,000–250,000 mg/L formation water Gas: dissolved gases in varying amounts depending on the
gas–oil ratio (GOR)
Hydrogen Sulfide: up to 1000 ppm by weight
(b) After treatment (dual-purpose operation): Sour wet crude must be treated to make it safe and environmentally acceptable for storage, processing, and export. Therefore, removing water and salt, is mandatory to avoid corrosion; separation of gases and H2S will make crude oil safe and environmentally acceptable to handle.
Water content (B.S.&W.): 0.3% by volume, maximum
Salt content: 10–20 lbs salt (NaCl) per 1000 barrels oil (PTB)
Vapor pressure: 5–20 psia RVP (Reid vapor pressure)
H2S: 10–100 ppmw
Crude oil is considered ‘‘sweet’’ if the dangerous acidic gases are removed from it. On the other hand, it is classified as ‘‘sour’’ if it contains as much as 0.05 ft3 of dissolved H2S in 100 gal of oil. Hydrogen sulfide gas
is a poison hazard because 0.1% in air is toxically fatal in 30 min.
Additional processing is mandatory—via this dual operation—in order to release any residual associated gases along with H2S present in the crude. Prior to stabilization, crude oil is usually directed to a spheroid for storage in order to reduce its pressure to very near atmospheric.

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STABILIZATION

the traditional process for separating the crude oil–gas mixture to recover oil consists of a series of flash vessels
[gas–oil separation plant (GOSP)] operating over a pressure range from roughly wellhead pressure to nearly atmospheric pressure. The crude oil discharged from the last stage in a GOSP or the desalter has a vapor pressure equal to the total pressure in the last stage. Usually, operation of this system could lead to a crude product with a RVP in the range of 4 to 12 psia. Most of the partial pressure of a crude comes from the low-boiling compounds, which might be present only in small quantities—in particular hydrogen sulfide and low-molecular-weight hydrocarbons such as methane and ethane.
Now, stabilization is directed to remove these low-boiling compounds without losing the more valuable components. This is particularly true for hydrocarbons lost due to vent losses during storage.
In addition, high vapor pressure exerted by low-boiling-point hydrocarbons imposes a safety hazard. Gases evolved from an unstable crude are heavier than air and difficult to disperse with a greater risk of explosion.
The stabilization mechanism is based on removing the more volatile components by (a) flashing using stage separation and (b) stripping operations.
As stated earlier, the two major specifications set for stabilized oil are as follows:
 The Reid vapor pressure (RVP)
 Hydrogen sulfide content
Based on these specifications, different cases are encountered:
Case 1: Sweet oil (no hydrogen sulfide); no stabilization is needed. For this case and assuming that there is a gasoline
plant existing in the facilities (i.e., a plant designed to recover pentane plus), stabilization could be eliminated, allowing the stock tank vapors to be collected [via the vapor recovery unit (VRU)] and sent directly to the gasoline plant,

Case 2: Sour crude; stabilization is a must. For this case, it is assumed that the field facilities do not include a gasoline plant.

It can be concluded from the above that the hydrogen sulfide content in the well stream can have a bearing effect on the method of stabilization.
Therefore, the recovery of liquid hydrocarbon can be reduced when the stripping requirement to meet the H2S specifications is more stringent than that to meet the RVP specified. Accordingly, for a given production facility, product specifications must be individually determined for maximum economic return on any investment.

Stabilization by Stripping
The stripping operation employs a stripping agent, which could be either energy or mass, to drive the undesirable components (low-boiling-point hydrocarbons and hydrogen sulfide gas) out of the bulk of crude oil. This
approach is economically justified when handling large quantities of fluid and in the absence of a VRU. It is also recommended for dual-purpose operations for stabilizing sour crude oil, where stripping gas is used for stabilization. Stabilizer-column installations are used for the stripping operations.

Crude Oil Sweetening
Apart from stabilization problems of ‘‘sweet’’ crude oil, ‘‘sour’’ crude oils containing hydrogen sulfide, mercaptans, and other sulfur compounds present unusual processing problems in oil field production facilities. The presence of hydrogen sulfide and other sulfur compounds in the well stream impose many constraints. Most important are the following:  Personnel safety and corrosion considerations require that H2S concentration be lowered to a safe level.
 Brass and copper materials are particularly reactive with sulfur compounds; their use should be prohibited.
 Sulfide stress cracking problems occur in steel structures.
 Mercaptans compounds have an objectionable odor.
Along with stabilization, crude oil sweetening brings in what is called a ‘‘dual operation,’’ which permits easier and safe downstream handling and improves and upgrades the crude marketability.
Three general schemes are used to sweeten crude oil at the production facilities:

Crude Sweetening

1. Stage vaporization with stripping gas. This process—as its name implies—utilizes stage separation along with a stripping agent.

Hydrogen sulfide is normally the major sour component having a vapor pressure greater than propane but less than ethane. Normal stage separation will, therefore, liberate ethane and propane from the stock tank liquid along with hydrogen sulfide.
Stripping efficiency of the system can be improved by mixing a lean (sweet) stripping gas along with the separator liquid between each separation stage.
The effectiveness of this process depends on the pressure available at the first-stage separator (as a driving force), well stream composition, and the final specifications set for the sweet oil.
2. Trayed stabilization with stripping gas. In this process, a tray stabilizer (nonreflux) with sweet gas as a stripping agent is used Oil leaving a primary separator is fed to the top tray of the column countercurrent to the stripping sweet gas. The tower bottom is flashed in a low-pressure stripper. Sweetened crude is sent to stock tanks, whereas vapors collected from the top of the gas separator and the tank are normally incinerated. These vapors cannot be vented to the atmosphere because of safety considerations. Hydrogen sulfide is hazardous and slightly heavier
than air; it can collect in sumps or terrain depressions.
This process is more efficient than the previous one. However, tray efficiencies cause a serious limitation on the
column height. For an efficiency of only 8%, 1 theoretical plate would require 12 actual trays. Because trays are spaced about 2 ft apart, columns are limited to 24–28 ft high, or a maximum of two theoretical trays.
3. Reboiled trayed stabilization. The reboiled trayed stabilizer is the most effective means to sweeten sour crude oils. A typical Its operation is similar to a stabilizer with stripping gas, except that a reboiler generates the stripping vapors flowing up the column rather than using a stripping gas. These vapors are more effective because they possess energy momentum due to elevated temperature.
Because hydrogen sulfide has a vapor pressure higher than propane, it is relatively easy to drive hydrogen sulfide from the oil. Conversely, the trayed stabilizer provides enough vapor/liquid contact that little pentanes plus are lost to the overhead.

what is Naphtha

what is Naphtha

Naphtha is a liquid petroleum product that boils from about 30°C (86°F) to approximately 200°C (392°F), although there are different grades of naphtha within this extensive boiling range that have different boiling ranges .

The term petroleum solvent is often used synonymously with naphtha. On a chemical basis, naphtha is difficult to define precisely because it can contain varying amounts of its constituents (paraffins, naphthenes, aromatics,
and olefins) in different proportions, in addition to the potential isomers of the paraffins that exist in the naphtha boiling range. Naphtha is also represented as having a boiling range and carbon number similar to those of gasoline a precursor to gasoline.

The so-called petroleum ether solvents are specific-boiling-range naphtha as is ligroin. Thus the term petroleum solvent describes special liquid hydrocarbon fractions obtained from naphtha and used in industrial processes and formulations.These fractions are also referred to as industrial naphtha. Other solvents include white spirit,
which is subdivided into industrial spirit [distilling between 30°C and 200°C (86°F–392°F)] and white spirit [light oil with a distillation range of 135°C– 200°C (275°F–392°F)]. The special value of naphtha as a solvent lies in its
stability and purity.

Naphtha Production and Properties:

Naphtha is produced by any one of several methods, which include (1) fractionation of straight-run, cracked, and reforming distillates or even fractionation of crude petroleum; (2) solvent extraction; (3) hydrogenation of cracked distillates; (4) polymerization of unsaturated compounds (olefins); and (5) alkylation processes. In fact, naphtha may be a combination of product streams from more than one of these processes.
The more common method of naphtha preparation is distillation. Depending on the design of the distillation unit, either one or two naphtha steams may be produced: (1) a single naphtha with an end point of about 205∞C (400∞F) and similar to straight-run gasoline or (2) this same fraction divided into a light naphtha and a heavy naphtha.The end point of the light naphtha is varied to suit the subsequent subdivision of the naphtha into narrower boiling fractions and may be of the order of 120∞C (250∞F).
Sulfur compounds are most commonly removed or converted to a harmless form by chemical treatment with lye, Doctor solution, copper chloride or similar treating agents Hydrorefining processes (Speight, 1999) are also often used in place of chemical treatment.When used as a solvent, naphtha is selected for low sulfur content, and the usual treatment processes remove only sulfur compounds. Naphtha with a small aromatic content has a slight odor, but the aromatics increase the solvent power of the naphtha and there is no need to remove aromatics unless odor-free
naphtha is specified.
The variety of applications emphasizes the versatility of naphtha. For example, naphtha is used by paint, printing ink and polish manufacturers and in the rubber and adhesive industries as well as in the preparation of edible oils, perfumes, glues, and fats. Further uses are found in the drycleaning, leather, and fur industries and also in the pesticide field. The characteristics that determine the suitability of naphtha for a particular use are volatility, solvent properties (dissolving power), purity, and odor (generally, the lack thereof).
To meet the demands of a variety of uses, certain basic naphtha grades are produced that are identified by boiling range.The complete range of naphtha solvents may be divided, for convenience, into four general categories:
1. Special boiling point spirits having overall distillation range within the limits of 30–165°C (86–329°F);
2. Pure aromatic compounds such as benzene, toluene, xylenes, or mixtures (BTX) thereof;
3. White spirit, also known as mineral spirit and naphtha, usually boiling within 150–210°C (302–410°F);
4. High-boiling petroleum fractions boiling within the limits of 160– 325°C (320–617°F).
Because the end use dictates the required composition of naphtha, most grades are available in both high- and low-solvency categories and the various text methods can have major significance in some applications and lesser significance in others. Hence the application and significance of tests must be considered in the light of the proposed end use.
Odor is particularly important because, unlike most other petroleum liquids, many of the manufactured products containing naphtha are used in confined spaces, in factory workshops, and in the home.

Acidizing Different Formations

ATTACHMENT DETAILS acidizingMuch of the worlds oil and gas comes from limestone (CaCO3) and dolomite (CaMg(CO3)2) formations, either in their relatively pure form or in the form of carbonate or siliceous sands cemented together with calcareous materials (CaCO3).
Dolomites are similar to limestones with the exception that they generally react more slowly with hydrochloric acid.
The primary method of stimulating wells drilled into these formations is to inject an acid treating solution. The acid dissolves part of the formation and may also dissolve other acid soluble material (mud damage, scales etc.), which is restricting or blocking the flow of oil or gas from the formation. Matrix acidizing increases the flow capacity of a producing formation when these restrictions are removed.

read more about Acidizing Concepts

Limestone and Dolomite
When either limestone and/or dolomite formation are stimulated, acid enters the formation through pores in the matrix of the rock or through natural or induced fractures. The type of acidizing used depends on, the injection rate and the number and size of the fractures present. Most limestone and dolomite formations produce through a network of fractures, though both formations can exist in an unfractured state. Normally, an interval will accept acid through the fractures more readily and at lower pressure than through the pore spaces. The acid solution reacts with the walls of the flow channels, increasing the width and conductivity of the fractures.
Most limestones and dolomite formations vary in acid solubility. Acid will attack the surface of the formation at varying rates, leaving an unevenly etched face. The existence of natural fractures, that occur at random intervals and in random sizes, contribute to the final uneven etching configuration.
The type of acid and strength are equally important factors in influencing the etch pattern. . The use of various types of acid (such as chemically retarded or emulsified acid), ensure that the volume of limestone or dolomite dissolved, will occur in an uneven pattern across the face of the fracture.

Gelled and cross-linked acids can also be used effectively. These fluids will create wider fractures and have reduced leak-off, resulting in less “worm holing” and deeper penetration due to the retarded reaction of the acid.
Chemically retarded acids are made effective by preceding the acid treatment with a hydrocarbon preflush containing an oil-wetting surface acting agent (surfactant) Due to the variable composition of the rock, the surfactant leaves a discontinuous oil film on the fracture face. The resulting acid break-through is irregular, creating an
improved etch pattern.
With emulsified acid, the resulting etch patterns are influenced by the rate at which acid penetrates the hydrocarbon outer phase of the emulsion and reacts with the The temperature of the formation should also be considered to ensure that the selection of either chemically retarded acid or delayed reaction acid is the one that is most suitable for the treatment recommended Acid volume and pump rate determine the acid contact time, during which the
fracture faces are exposed to live acid. Contact time has a direct bearing on the amount of etching obtained. However, increasing the volume of an acid treatment does not appreciably increase the depth of penetration. Thus, the benefit of a treatment with a contact time greater than the spending time of the acid, can be attributed to acid etching, which results in additional flow conductivity.
The “shut-in time”, or the length of time a well is closed in after a stimulation treatment, is determined by the type of acid used and by such downhole factors as:
· Type of formation.
· Bottom-hole temperature.
· Bottom hole pressure.
After an acid solution has been neutralised by reaction with the formation, it is no longer a stimulation agent. However, it may become harmful to the formation permeability if allowed to remain downhole.
Hydrochloric acid reacts so rapidly with limestone formations that it is essentially neutralised by the time the acid has been completely placed. This neutralisation generally occurs at all ranges of temperature and pressure. Limestone formations incorporate varying amounts of insoluble impurities, which can plug permeability if allowed to come to rest. Therefore, it is important to remove the neutralised hydrochloric acid as soon as possible. The shut-in time with such formations is zero.
Figures 2 to 5 show the relative reaction rates of 15% hydrochloric acid with limestone and dolomite formations at different temperatures. When chemically retarded acids like super retarded acids (SRA), delayed reaction systems (Super Sol Acid (EQH)), Sta-Live and emulsified acids like SRA-3 are used, the reaction time exceeds the displacement time. This is also true for gelled and cross-linked acids (Gelled Acid, Gelled Acid XL, XL Acid II). Here, the shut-in time may be extended if there is sufficient bottom-hole pressure to promote rapid cleanup.
For reaction times of retarded acids consult the engineering product bulletin pertaining to the acid system used.

Acidizing Concepts

Acid Types
acidizingAlthough many acid compounds are available to the oil industry, only the following types have been proven economically effective in oil well stimulation:
Inorganic Acids (Strong).
· Hydrochloric Acid (HCl).
· Hydrofluoric Acid (HCl:HF).
Other inorganic acids include Sulphamic, Sulphuric and Nitric acids.
Organic Acids (Weak).
· Acetic Acid and Glacial Acetic Acid.
· Acetic Anhydride.
· Citric Acid.
· Formic Acid.

Inorganic Acids
Hydrochloric Acid (HCl).
Hydrochloric acid is an inorganic acid and is the most commonly used acid in oil well stimulation. Hydrochloric acid has many advantages in its application as follows:
· Low cost and availability.
· Easily inhibited to prevent attack on oil-field tubulars.
· Surface tension can be controlled to aid in :
– Penetration.
– Wetting properties.
– Exhibit detergency.
– Reducing friction pressure.
· Can be emulsified for slower reaction rate.
· Exhibit de-emulsification properties for rapid clean up.
· Most reaction products are water soluble and easily removed.
· Additives to minimise or eliminate insoluble reaction products can be applied.
It has long been recognised that hydrochloric acid is the best field acid for most applications. It is however, not without limitations. Hydrochloric acid is quite reactive; therefore, it will spend quite rapidly on some formations. It is essential with hydrochloric acid to size acid treatments and pump rates to optimise this property.

read more about Acidizing Different Formations

The reaction rate also dictates the selection of additives that will perform their functions during the relatively short spending time. These same additives must survive the spending process and function in the spent acid. Certain materials are soluble in hydrochloric acid but not necessarily in the spent acid water. For example, calcium sulphate can be partially solubilised by hydrochloric acid, but will crystallise out as scale when the acid spends. Iron oxide will dissolve in hydrochloric acid but will re-precipitate, as the acid spends, at about a pH of 2.0. These properties require
the selection of additives that will circumvent these problems.
Hydrochloric acid is normally pumped in concentrations ranging from 3.0% to 28%.
The low concentration acids are used for the removal of salt plugs and emulsions. The high concentration acids are selected to achieve longer reaction times and to create larger flow channels. By far the most frequently used strength is 15%, for the following reasons :
· Less cost per unit volume than stronger acids.
· Less costly to inhibit.
· Less hazardous to handle.
· Will retain larger quantities of dissolved salts in solution after spending.
In addition to the above advantages 15% hydrochloric acid will also provide other specific properties such as emulsion control and silt suspension. The general uses for hydrochloric acid are as follows :
· Carbonate acidizing – Fracture and Matrix.
· Sandstone acidizing – Matrix only.
· Preflush for HCl:HF mixtures.
· Post-flush for HCl:HF mixtures.
· Acidizing sandstones with 15% to 20% carbonate content.
· Clean-up of acid-soluble scales.
· Perforation washes.
Pure hydrochloric acid (muriatic acid) is a colourless liquid, but takes on a yellowish hue when contaminated by iron, chlorine, or organic substances. It is available commercially in strengths up to 23.5° Bé (Baumé scale) or 38.7% percent by weight of solution.
Some processes dictate that hydrochloric acid is not the most suitable acid to use. In these cases, alternatives, such as organic acids (acetic and formic) may be used.
These acids are used because of their inherently retarded nature, their ability to be used at higher temperatures and their solvation ability in “dirty” formations. The primary objection to the use of organic acids is their cost and their lack of effectiveness in removing limestone.

Other acids are also used in limited quantities. An example is citric acid, which can be used both alone, or as a component of an acid blend, or for use as a stabiliser, buffer and iron control agent. Also sulfamic acid has been used in the oil industry on a “do it yourself” basis. Its usage is recommended because of its low corrosivity,
although it is limited by its ability to strip chrome from chrome pumps and by its relatively high cost.

Hydrofluoric Acid (HF).
Hydrofluoric acid, another inorganic acid, is used with hydrochloric acid to intensify the reaction rate of the total system and to solubilise formations, in particular sandstones. In general hydrofluoric acid is used as follows :
· It is always pumped as an HCl:HF mixture.
· Ensure that salt ion contact is prevented.
· Sandstone matrix acidizing.

· Removal of HCl insoluble fines.
· Normal concentrations 1.5% to 6.0%.
· One gallon of 12:3 HCl:HF will dissolve 0.217 pounds of sand.
Hydrofluoric occurs as a liquid either in the anhydrous form (where it is fuming and corrosive), or in an aqueous solution (as used in well stimulation). Hydrofluoric acid attacks silica and silicates, (glass and concrete). It will also attack natural rubber, leather, certain metals such a cast iron and many organic materials.
In well stimulation, hydrofluoric acid is normally used in combination with hydrochloric acid. Mixtures of the two acids may be prepared by diluting mixtures of the concentrated acids with water, or by adding fluoride salts (e.g. ammonium bifluoride) to the hydrochloric acid. The fluoride salts release hydrofluoric acid when dissolved in hydrochloric acid.
Hydrofluoric acid is poisonous, alone or in mixtures with hydrochloric acid, and should be handled with extreme caution.Other Inorganic Acids.
Some consideration has been given to using sulfuric and nitric acids; however, these acids are not used extensively in the oil industry today. The reasons for the lack of use are; sulfuric acid will form insoluble precipitates, and nitric acid often forms poisonous gases during its reaction with certain minerals.

 Organic Acids.
These acids are used in well stimulation basically because they have a lower corrosion rate and are easier to inhibit at high temperatures than hydrochloric acid. Although mixtures of organic acids are considered corrosive to most metals, the corrosion rate is far lower than that of hydrochloric or hydrofluoric acid, therefore, organic acids are used when long acid-pipe contact time is required. An example of this is when organic acid is used as a displacing fluid for a cement job. The organic acids is left in the production string. and is subsequently used as the perforating fluid.
Organic acids are also used when metal surfaces of aluminium, magnesium, and chrome are to be contacted, such as in trying to remove acid-soluble scales in wells with downhole pumps in place. They can also be used as iron control agents for other acid systems. Many organic acids are available, but the four most commonly
used are :
· Acetic Acid.
· Acetic Anhydride.
· Citric Acid.
· Formic Acid.

Acetic Acid (CH3COOH).
Acetic acid is a colourless organic acid soluble in water in any proportion and in most organic solvents. Although mixtures of acetic acid with water are considered corrosive to most metals, the corrosion rate is far lower than that of hydrochloric and hydrofluoric acids. Acetic acid is easy to inhibit against corrosion and is used frequently as a perforating fluid where prolonged contact times are required. With this ability, the acid is sometimes used as a displacing fluid on a well cementing job, where the contact time may be hours or days before perforating takes place. This ability is beneficial in three ways:
· Reduces formation damage. The first fluid two enter the formation will be an acid or low pH fluid which will react with carbonate or the calcareous materials of a sandstone formation.
· Reduces clay swelling.
· Can be used where aluminium, magnesium or chrome surfaces must be protected.
The relation of dissolving power of one gallon of a 15% concentration of acetic acid compared to that of hydrochloric acid and formic acid at the same volume is listed in Table 1, page 3. The cost of acetic acid per unit, based on dissolving power, is more expensive than either hydrochloric acid or formic acid.
Normally, acetic acid is used in small quantities or with hydrochloric acid, as a delayed reaction, or retarded acid. The general uses and properties of acetic acid are as follows:
· Acetic acid is relatively weak.
· Normal concentrations of 7.5% to 10% when used alone.
· Mainly used in hydrochloric acid mixtures.
· Used as an iron control additive.
· Carbonate acidizing.
· Perforating fluid.
· Retarded acids.
Commercially available acetic acid is approximately 99% “pure”. It is called glacial acetic acid because, ice-like crystals will form in it at temperatures of approximately 60° F (16° C) and will solidify at approximately 48° F (9° C). When glacial acetic acid is mixed with water, a contraction occurs. For this reason, the amount of acetic acid and the amount of water normally total more than the required volume.
Care should be exercised when handling acetic acid. This solution in concentrated form can cause severe burns and fume inhalation can harm lung tissue

Acetic Anhydride Acid.
Acetic anhydride is the cold weather version, for use instead of acetic acid due to its lower freezing point of 2.0° F (-17° C). The properties of acetic anhydride are the same for those of acetic acid, the only changes are those in relation to volumes used.
A comparison of acetic anhydride to acetic acid shows that one gallon of acetic anhydride mixed with 0.113 gallons of water is equivalent to 1.127 gallons of acetic acid. Expressed alternatively one gallon of acetic acid is equivalent to 0.887 gallons of acetic anhydride mixed with 0.101 gallons of water.
When mixing acetic anhydride always add it to water or dilute acid. If water or dilute acid is added to acetic anhydride, an explosion will occur due to a rapid increase in temperature caused by the chemical reaction.
As with acetic acid, care should be exercised when handling acetic anhydride as this solution in concentrated form can cause severe burns and fume inhalation can harm lung tissue.

Citric Acid (C6H8O7)
Iron scales are normally found in the casing and tubing in wells and sometimes as the mineral deposits in the formation rock itself. When hydrochloric acid solutions come into contact with these scales or deposits, the iron compounds are partially dissolved and are carried in solution as iron chloride. As the acid becomes spent,
the pH rises above 2.0, allowing the iron chloride to undergo chemical changes and re-precipitate as insoluble iron hydroxide. This re-precipitation can reduce formation permeability and injectivity.
Citric acid (Ferrotrol 300) is a white granular organic acid material. It is used to “tie up” dissolved iron scales and prevent re-precipitation of dissolved iron from spent hydrochloric acid solutions. Normally, citric acid (often referred to as a sequestrant or sequestering agent), is used with X-14 to make the effects of suspension more
stable.
Citric acid is not used alone as an acid treating solution itself but is used in hydrochloric acid solutions known as sequestering acids (SA-systems) for the control of iron.
The amount of citric acid added to the hydrochloric acid system depends upon the amount of iron that is present. The first 50 pounds of citric acid added to 1000 gallons of acid, will sustain 2000 parts per million (ppm) of iron in solution (SA-2).
Each additional 50 pounds of citric acid added will increase its sequestering property by an additional 2000 ppm

Formic Acid (HCOOH)
Formic acid is the simplest of the organic acids and is completely miscible (capable of being mixed) with water. Formic acid is stronger than acetic acid yet weaker than hydrochloric acid. Formic acid is used in well stimulation, most frequently in combination with hydrochloric acid as a retarded acid system for high-temperature wells. The percentage of formic acid used in such applications is commonly between 8.0% and 10%. Formic acid can be easily inhibited, but not as effectively as with acetic acid at high temperatures and long contact times. The properties and uses of formic acid parallel those of acetic acid as stated below:
· Formic acid is relatively weak.
· Seldom used alone.
· Mainly used in hydrochloric acid mixtures.

Corrosion inhibitor aid.
· Hot wells.
· Retarded acids.
Acetic acid, acetic anhydride and formic acid are used when exceptionally retarded acid is needed because of extreme temperature or very low injection rates. At high temperatures, blends of organic and hydrochloric acid are much more successfully inhibited by organic inhibitors, than when hydrochloric acid is used alone. This property minimises the danger of hydrogen embrittlement of steel associated with hydrochloric acid treatments in high-temperature wells. Organic acid concentrations of up to 25% by weight are required, making acid treatment costs increase. Organic acids do not give as much reacting capability as hydrochloric acid treatments.