Ecole Nationale Suprieure de Gologie

Producing the reservoir Flow Dynamics & Production Monitoring

& Well Production Optimization

Prepared by students of International Master SRE

Talgatbek BAZARBEKOV Amir KUVANYSHEV

Nurlan SHAYAKHMETOV Sergey USMANOV

Nancy 2014

Contents

1. Flow dynamics and production monitoring

1.1. Production vs well and surface equipment

1.2. Producing interval evaluation

1.3. Well testing and monitoring

1.4. Permanent monitoring

1.5. Subsea well / Flow optimization

1.6. Reference

2. Well production optimization

2.1. Assuring flow through tubular

2.2. Production zone selection

2.3. Fracturing

2.4. Well productivity optimization

2.5. Work-over

2.6. Reference

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1. Flow Dynamics and Production Monitoring From the flow dynamics, we know several types of two phase flow regimes which varies

by the types of wells and rock, flow properties.

For vertical well:

Bubble flow a lot of discrete gas bubbles widespread in a continuous liquid phase. Bubbles can be different in size and form, but most of them are almost spherical and size is much smaller than well diameter.

Slug flow with increasing of widespread gas volume in the liquid, merging possibility of several gas bubbles are increases and we will have gas slugs. Which has size close to well diameter and characteristic shape resembling a bullet.

Annular flow At one time interfacial share of high velocity gas located on the liquid film will dominant over the gravity and liquid will move from center to sides. Gas phase can haven't any liquid (a) or liquid can appear at gas phase as small droplets (b). This flow regime a particularly stable.

a) b)

Mist flow At very high gas flow velocities the annular film thinned by the shear of the gas core on the interface until it becomes unstable and is destroyed, such that all liquid droplets will located in the continuous gas phase. This flow regime is opposite to bubble flow.

The motion in the horizontal tubes is almost the same as in the vertical tubes, however in

the horizontal wells we have gravity effect and distribution of the bubbles in two-phase flow pattern depends the gravity. Two phase flow patterns for horizontal wells:

Bubble flow gas bubbles are dispersed in the liquid with the high concentration at the upper half of the well due to liquid gas density ratio. When the shear forces are dominant, bubbles tend to disperse uniformly in the tube.

Stratified flow at the liquid and gas flow velocities, this two phases are completely separated along the height. That means due to difference between gas and liquid density, gas will flow up to the top of the well and liquid will flow down to the bottom of the well.

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Stratified-wavy flow by the velocity increasing appears waves that forms at the separation line and travel to the direction of the flow. The heights (amplitudes) of these waves are changing and depends on the relative velocity of the two phases. But they are can't reach top of the well in this flow regime.

Slug flow by the increasing of the gas velocity, the interfacial waves become higher and higher so as they are rich and wash the top of the well. Some of this waves will have bubbles and by the increasing of the velocity bubbles are start to unit into one slug, so one will have slug flow with the gas slugs at the top and with the liquid at the bottom of the horizontal well.

Mist flow as a vertical wells at the high velocities of the gas, all the liquid may be stripped from the wall and entrained as a small droplets in the continuous gas phase.

Many scientists try to analyze the changing of types of the flows and find dependence of

these changing by the fluid or rock properties. Fair (1960), Hewitt and Roberts (1969) famous and widely used two phase flow pattern maps illustrated in Figure 1 and Figure 2 respectively. To use flow pattern map which was proposed by Fair (1960) one should calculate X axis by the formula shown below and the mass velocity (here in lb/h ft).

( x1 x)

0,9

( LG )0,5

( G L)0,5

there are:

G gas viscosity, G gas density, L liquid viscosity, L liquid density, x vapor quality

Using this two values one can locate the point between bubble flow, slug flow, annular flow, mist flow and find out the type of two phase flow pattern.

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Figure 1. Two phase flow pattern map of Fair (1960) for vertical tubes [1]

To use two phase flow pattern of Hewitt and Roberts (1969), one should calculate mass velocities of the liquid and gas phase using the vapor quality. Then the values of the x and y coordinates are determined and the intersection of these two values on the map identifies the flow pattern predicted to exist at this flow conditions.

Figure 2. Two phase flow pattern map of Hewitt and Roberts (1969) for vertical tubes [1]

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1.1. Production vs Well & Surface Equipment When the well is opened for producing the pressure distribution in the reservoir is changing,

which can be seen in decreasing of bottomhole pressure (Fig. 1):

Figure 1. Scheme of the pressures in the reservoir-well system, there: Ps pressure at the

separator, Pwh pressure at well head, Pwf bottomhole pressure, Pr average reservoir pressure [9]

There are: Safety valve - is a valve mechanism which automatically releases a substance from a boiler,

pressure vessel, or other system, when the pressure or temperature exceeds preset limits. Bottomhole restriction a restriction in a profile near the bottom of the well that allows some gas

expansion and holds a backpressure on the formation. Rarely used, but considered for hydrate control.

The term separator in oilfield terminology designates a pressure vessel used for separating well fluids produced from oil and gas wells into gaseous and liquid components. A separator for petroleum production is a large vessel designed to separate production fluids into their constituent components of oil, gas and water.

D P 1 = P r - P wfs - Loss in Porous Medium D P 2 = P wfs - P wf - Loss across Completion D P 3 = P wf - P wh = Loss in Tubing D P 4 = P wh - P s = Loss in Flowline D P T = P r P s = Total pressure loss Due to this pressure drops we will have outflow and inflow. As mentioned above we can predict

that flow has straight dependence on the pressure i.e. of pressure difference between surface pressure and reservoir pressure. According to the Darcys law, which defines the fluid movement in porous media, the velocity of flow is related to the pressure gradient, so it is controlled by the surface equipment. We can't influence to reservoir pressure but we can use choke to change the surface pressure.

In oil and gas production a choke manifold is used to control the pressure from the well head. It consists of a set of high pressure valves and at least two chokes. These chokes can be fixed or adjustable or a mix of both. The redundancy is needed so that if one choke has to be taken out of service, the flow can be directed through another one. By lowering pressure the retrieved gases can be flared off on site.

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Figure 2. Inflow performance relationship. Production rates at various drawdown

pressures are used to construct the IPR curve, which reflects the ability of the reservoir to deliver fluid to the wellbore. Combining this with a curve reflecting the tubing performance

identifies the operating point. Determination of rate vs. pressure is often referred to as the reservoir inflow performance, which is

a measure of the ability of the reservoir to produce gas to the wellbore. The inflow performance curve is a plot of bottomhole pressure vs. production rate for a particular well determined from the gas well deliverability equations depicts a typical gas well inflow performance curve. This curve allows one to estimate the production rate for different flowing bottomhole pressures readily.

The pressure drop in any component, and thus in either the inflow or outflow section of the system, varies as a function of flow rate. As a result, a series of flow rates is used to calculate node pressures for each section of the system. Then, plots of node pressure vs. production rate for the inflow section and the outflow section are made. The curve representing the inflow section is called the inflow curve, while the curve representing the outflow section is the outflow curve. The intersection of the two curves provides the point of continuity required by the systems analysis approach and indicates the anticipated production rate and pressure for the system being analyzed.

The relationship between well inflow rate and pressure drawdown can be expressed in the form of a Productivity Index, denoted PI or J, where:

Q= J (Pws Pwf ) or J = Q

Pws Pwf

Q0=kh(Pav Pwf )

141.2 0 B0[ ln (r erw 3 /4)]

There: P - pressure (psi), Pav - average pressure, k - permeability (md) h - height (ft) re - drainage

radius (ft) rw - wellbore radius (ft) O - fluid viscosity (cP) Bo - formation volume factor (bbls/stb) When the inflow is modeled the pressure drop, production fluid properties (viscosity) and the

reservoirs parameters (permeability) is taking into account, to calculate the out-flow the influence of the well and surface equipment is of a great importance. Such calculation can be used to define optimal flow conditions and necessary equipment (tubing, surface facilities). By combining both, in-flow and out-flow models, one obtains such called full-field model, which can be used in planning of production processing and transport.

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1.2. Producing Interval Evaluation During the production we can have some mismatch because of heterogeneity of reservoir. For

example, one can have well with perforation which located above water-oil contact, but on the surface we can deplete much more water than it should be. That's happened when we have some heterogeneities like cracks etc. To find this overflow zones we use logging equipment like:

Flow meter tool using which we can calculate locally quantification of volume fluid movement, illustrated in Fig. 1.

Water holdup electrical sensor which can indicate appearance of water by the resistivity, as reservoir brine has resistivity lower than oil or gas, illustrated in Fig 2.

Figure 1. Flow meter [15] Figure 2. Water holdup [17] Gas holdup sensor which can indicate appearance of gas presented in Fig. 3, for example Ghost

gas holdup which uses Schlumberger indicate gas appearance by the LED light reflection and designed so that the amount of reflected light is much greater when the sensor is in gas than when it is in liquid. Work principle of Ghost holdup illustrated in Fig. 4.

Figure 3. Gas hold up [16]

Figure 4. Work principle of Ghost hold up [14]

Now firms like Schlumberger have many possibilities and new technologies so that one can measure multi-phase flow rate, using equipment presented above. One of many possible PS Platform configurations recommended for multiphase flow analysis presented in Fig. 5.

Figure 5. PS Platform configurations recommended for multiphase flow analysis [14] 8

All information which one takes from the sensors are processed at the special computer utilities and the specialist can present production profile, find overflow zones and re-perforate well so that this zones will be closed (Fig. 6).

Figure 6. Multiphase flow logging measurement. a) before b) after re-perforation [14]

Horizontal and highly deviated wells are drilled to target specific pay zones in the oil and

gas reservoirs. They may increase the recovery percentage from onshore and offshore fields. The ability to drill such wells provides cost effective means for extracting resources from reservoirs, that may not otherwise have been economically viable. Due to the increase in highly deviated and horizontal wells, there is a need for intervention technologies that allow for down-hole operations in such wells. For this operations will be developed the wireline tractor illustrated in the Fig.7.

Applications of the wireline tractor:

Production logging Logging while tractoring Pipe recovery Perforation Plug setting Tractor jar Drift Can be used in tandem to negotiate restrictions in wellbore Anchor and conveyance for rotational services

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Key features of the wireline tractor:

Cost effective wireline conveyance in horizontal wells Flexible arms follow ID variations in well Compatible with 3rd party tools DC voltage operated Hydraulic drive mechanism Helicopter transportable Short toolstring length compared to similar products on the market [19].

Figure 7. Wireline tractor [18]

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1.3. Well Testing & Monitoring Well Testing is the technique allows measurement of reservoir data production

capabilities and reservoir properties permeability, pressure, temperature, fluid properties, flow rate, productivity etc under dynamic conditions for both, shut-in and flowing well.

Usually, well testing suggests influencing the pressure distribution in the reservoir by some operation with well, i.e. one changes the chock size in the chock manifold which leads to changing a flow rate and, consequently, to some pressure perturbations in reservoir tested. Another possibility is to shut in the well totally (producer or injector) after some period and pick the pressure response (pressure fall-off curve for injection well and pressure build-up curve for production well). Also surface and in-situ sampling is used.

Well Testing can be performed at different stages of well life:

Drilling Open hole DST (drillstem test) Cased hole DST

Exploration well DST Development well DST and/or Production Test

Well testing methods

Openhole and cased hole, no completion. Conventional deliverability tests, involving extensive surface and downhole equipment, are designed to simulate the production characteristics of new wells. Fig. 1 shows a typical surface onshore layout for an exploration well test and a sketch of the drillstem test (DST) string of downhole testing tools (the purpose of well testing equipment is given). Also, Multiphase tester (Fig. 2) can be used as shown in the Permanent Monitoring Chapter, replacing the bigger part of the equipment shown in Fig.1.

Wireline testing. Wireline tests are performed mostly in open hole using a cable-operated formation tester and sampling tool anchored at depth while reservoir communication is established through one or more pressure and sampling probes. Fig. 3 shows typical configurations for testing and sampling with the Modular Formation Dynamics Tester tool.

Production or injection test with completion string in place. Production and injection well tests, performed using production logging tools, are conducted to obtain pressure and optional flow measurements. Fig. 4 shows a sketch of a basic version of the Schlumbergers PS Platform new-generation production services platform, equipped with a gas holdup sensor [20].

DST Production test Retrievable packer Tubing or Drill pipe Flowhead

Permanent packer Tubing Christmas Tree (X-tree)

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Figure 1. Typical surface onshore layout for an exploration well test and a sketch of the

drillstem test [21, 22] 1-the Flowhead controls the well pressure 2-the choke manifold controls the flow and the pressure. 3-the heater (or steam exchanger) is used to raise the effluent temperature to fight hydrates (gas well), and to break emulsion or to reduce foam and viscosity (oil well), and improve burning. 4-the separator is use to separate, measure and sample the three phases of the effluent (to obtain accurate & representative data, separator must be run under steady conditions) 5-the gauge tank are used to store oil, to calibrate the liquid meters, to measure the shrinkage and low liquid flowrate. 6-the oil is disposed of through the burner located at the extremity of the booms to reduce heat radiations towards the rig. 7-the gas is burned separately through a gas flare located on the burner booms

Figure 2. Ultra-deep water multi-phase flow measurement [23]

1 2

3 4 5

6

7

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Figure 3. Typical MDT configurations for formation testing and sampling [20]

Figure 4. Sketch of a basic PS Platform tool for production logging and testing in production and injection wells [20]

Processing of Well testing During a well test, a particular flow rate schedule is applied to the tested reservoir, by

using flow control equipment (conventional testing) or a software-selected drawdown routine (wire-line formation testing). The pressure response and the flow rates obtained are recorded versus time. From the measured pressure, and from predictions of how reservoir properties influence this response, the estimation of these properties (permeability, skin factor) becomes possible. A particular aspect of well testing is formation fluid sampling, which is one of the main reasons wells are tested [20].

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Measurements from well testing

Measurements necessary to satisfy these aims are: o Rates of each fluid produced o The bottom hole pressure and temperature behavior o PVT study of representative reservoir samples

The primary purpose of a DST or production test

Determine the nature of fluids produced. o PVT tests to be performed on the bottom-hole or recombined samples.

Define the well productivity. One of special parameters measured during well testing is well performance, or productivity the measure of a well completions ability to produce, expressed in volume of gross liquid produced per day per unit of differential pressure between the static reservoir pressure and the wells flowing bottomhole pressure. The productivity carries variety of useful information, i.e. the hydroconductivity, effective thickness etc o Productivity index and IPR plot for oil wells. o Deliverability curve and absolute open flow for gas wells.

Evaluate the characteristics of the producing formation. o Static pressure. o Formation flow capacity (Kh), reservoir heterogenities, limits.

Evaluate any formation damage o Determine if acidizing or other treatment is required. o Control the results of the stimulation or treatment [21]

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1.4. Permanent monitoring Nowadays new technologies allow permanent monitoring of reservoir parameters, such as

pressure, temperature, fluid produced etc. All these data allow reservoir engineer to adapt the reservoir model to the instant real conditions and effectively plan measures to meet the different tasks (pressure maintenance, recovery factor, water cut control etc)

To make a monitoring of reservoir pressure and temperature its important to place the sensors in vicinity of the perforation interval to avoid effects occurred in the tubing string. Optic technologies applied (Fig.1).

Figure 1. Bottomhole Pressure-temperature monitoring [24]

Moreover it is possible to monitor the production fluid in-situ. To meet this Weatherford

provides the complex solution Downhole optical multiphase flowmeter (Fig.2).

Figure 2. Downhole optical multiphase flowmeter [25]

The optical multiphase flowmeter technology is based on a flow-velocity measurement and a speed-of-sound measurement where the speed of sound is proportional to volume fraction of oil, water, and gas in the flowing mixture. The flowmeter is deployed as part of the production tubing and is typically integrated with one or two Weatherford optical pressure and temperature gauges ported to tubing and/or annulus. The tool is connected to the perforated interval and

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isolated from the other space by packer. Such type of installation allows continuous data acquisition [26]. The advantages of this kind of tools meet the majority of permanent monitorings advantages:

Continuous data acquisition Identification and localization of production anomalies in real-time Local control in multi-lateral wells (multi-zone intelligent completions) Direct determination of well productivity index Reduction of surface well tests and surface facilities Subsea installations with fiber in the umbilical.

The disadvantage of the technology is price and laborious maintenance. Downhole flow monitoring at the most basic level can be considered as simply an alternative flow measurement required for well production optimization. In subsea environments a downhole meter can be the most cost-effective option for adequate data gathering [27].

Using the permanent monitoring, engineers perform the continuous cycle: Monitoring-Data manipulation-Decision-Execution-Monitoring-Data manipulation

Also surface flow testing is used to monitor the production fluid. It can be convenient method when all the production is separated in the surface, so one can define a phase composition (oil, gas, water) produced. The big disadvantage of such method is an involving of extensive surface and downhole equipment as it is shown in previous chapter.

Also, therere some problems, related with separation of the production [28]:

It can take several hours to obtain reliable flowrate measurement from a test separator. Some oil remains in water, some gas in oil etc, leading to inaccuracy on flowrate

measurements. Slugs, foam, emulsion. Viscous oil: not easy to separate the oil from water

However, nowadays Schlumberger and some others provide an opportunity to avoid such involving by using PhaseTester Vx (Fig. 3).

Figure 3. Schematic View of a PhaseTester Vx [29] 16

This multiphase well testing unit allows carrying out In-line Flow Measurements:

Venturi meter and Cross correlation of different sensors data (Gamma-ray, electricalcapacity and conductivity etc) to determine the velocity of the multiphase flow and amass flowrate

Gamma-ray (densitometer defines a high contrast between liquid and gas), Microwave(microwave sensor between water and hydrocarbons) and Dielectric constant(permittivity will be different for each of the three components in an oil/gas/watermixture) to define the phase composition of producing fluid.

Both, permanent and temporary measurements can be processed, which allows to update the reservoir model continually. In total such technology provides more accurate surface measurements in any flow conditions. The advantages are:

Independent of flow regimes More accurate than a separator No flowing calibration Continuous monitoring Very low pressure loss Based on physical principles With no moving / intrusive parts Safety Environmentally friendly No flaring (Zero Emission Testing) No pumping and leak risks

Also, other solutions for multiphase in-flow measurement which use sonar technologies exist (Fig. 4).

Figure 4. ACTIVESONAR (a) and PASSIVESONAR (b) flowmeters [30]

b) a)

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Such type of equipment for permanent flow monitoring provides wide spectrum of data and easy to transport and install (Fig. 5).

Figure 5. Multiphase flow measuring [31]

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1.5. Sub-sea well. Flow optimization Subsea oil field developments can be splited into categories to distinguish between the

different facilities and approaches that are needed [32]:

Shallow water: 600 feet, floating drilling vessels and floating oil platforms are used, and remotely operated underwater vehicles are required)

Most of the new oil fields are located in deep water and are generally referred to deepwater systems. Development of these fields sets strict requirements for verification of the various systems functions because of the high costs and time involved in changing a pre-existing system due to the specialized vessels with advanced onboard equipment.

Subsea production systems can include numerous wells on a template or clustered around a manifold and transferring to a fixed or floating facility, or directly to an onshore installation.

Subsea production systems can be used to develop reservoirs, or parts of reservoirs, which require drilling of the wells from more than one location. In such complicated conditions the incidents consequences can be extremely dangerous, that is why the requirements for subsurface equipment are very strict. The development of subsea oil and gas fields requires specialized equipment, which must be reliable enough not only to safeguard the environment, but also to make the exploitation of the subsea hydrocarbons economically feasible. The deployment of such equipment requires specialized and expensive vessels. Any requirement to repair or intervene with installed subsea equipment is very expensive [33].

The general scheme of sub-sea production is shown in Fig. 1. The wells are connected to subsea production manifold, the production is gathered by manifold into pipeline and can be processed subsea or pumped via riser, which insures the connection between pipeline and floating production platform. The umbilical between platform to manifold allows control and well monitoring.

Figure 1. Offshore capabilities [34]

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Nowadays Subsea Processing is available [35]: Subsea processing solutions: Why Subsea Processing: 3 phase separation Gas & Liquid Separation Sand Removal Water removal and reinjection Gas removal and reinjection Single and Multiphase Boosting Gas compression Raw Seawater Injection

Increased recovery Accelerate production Reduced Capital Expenditure Makes it possible to: -connect satellite fields to existing infrastructure -exploit fields that are normally inaccessible -exploit costly infrastructure fully throughout the systems operational period -depressurize system as a hydrate strategy Influence on the environment will decrease Reduces water disposal to sea Enhances flow management

Subsea well intervention (Fig. 2) offers many challenges and requires much advance

planning. The cost of subsea intervention has in the past inhibited the intervention but in the current climate is much more viable. These interventions are commonly executed from light/medium intervention vessels or mobile offshore drilling units for the heavier interventions such as snubbing and workover drilling rigs.

The special arrangement (intervention riser system) and multiple control is applied to obtain an ultimate connecting. Such system allows for the deployment and free movement of fluids, coiled tubing, wireline or slickline within the riser system.

Figure 2. Sub-Sea Production & Well intervention [36]

Riser system

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1.6. Reference 1. Thome, John R. "Two Phase Flow Patterns." Engineering Data Book. Lausanne:

Wolverine Tube, 2004. N. pag. Print. 2. Bratland, Ove, Dr. "The Flow Assurance Site." Chapter 1, Pipe Flow 1 Single-phase

Flow. Ove Bratland, 2010. Web. 12 Dec. 2014. 3. Baker, O., 1954, Simultaneous Flow of Oil and Gas, Oil and Gas Journal, Vol. 53, pp.

185. 4. Bonjour, J., and Lallemand, M., 1998, Flow Patterns during Boiling in a Narrow Space

between Two Vertical Surfaces, International Journal of Multiphase Flow, Vol. 24, pp. 947-960

5. Fukano, T., Kariyasaki, A., and Kagawa, M., 1989, Flow Patterns and Pressure Drop in Isothermal Gas-Liquid Flow in a Horizontal Capillary Tube, ANS Proceedings, 1989 National Heat Transfer Conference, ISBN 0-89448-149-5, ANS, Vol. 4, pp. 153- 161.

6. Hewitt, G.F., 2000, Fluid Mechanics Aspects of Two-Phase Flow, Chapter 9, Handbook of Boiling and Condensation, Eds. Kandlikar, S.G., Shoji, M., Dhir, V.K., Taylor and Francis, NY.

7. Coleman, J.W., and Garimella, S., 2000, Two-phase Flow Regime Transitions in Microchannel Tubes: The Effect of Hydraulic Diameter, HTD-Vol. 366-4, Proceedings of the ASME Heat Transfer Division-2000, Vol. 4, ASME IMECE 2000, pp. 71-83.

8. Barnea, D., Luninsky, Y., and Taitel, Y., 1983, Flow Pattern in Horizontal and Vertical Two-Phase Flow in Small Diameter Pipes, Canadian Journal of Chemical Engineering, Vol. 61, pp. 617-620.

9. Gilbert, W.E. 1954. Flowing and Gas-Lift Well Performance. Drill. & Prod. Prac., 126-57. Dallas, Texas: API.

10. Mach, J., Proano, E., and Brown, K.E. 1979. A Nodal Approach for Applying Systems Analysis to the Flowing and Artificial Lift Oil or Gas Well. Paper SPE 8025 available from SPE, Richardson, Texas.

11. Brown, K.E. 1984. The Technology of Artificial Lift Methods, 4. Tulsa, Oklahoma: PennWell Publishing Co.

12. Greene, W.R. 1983. Analyzing the Performance of Gas Wells. J Pet Technol 35 (7): 1378-1384. SPE-10743-PA. http://dx.doi.org/10.2118/10743-PA.

13. Brown, K.E. and Lea, J.F. 1985. Nodal Systems Analysis of Oil and Gas Wells. J Pet Technol 37 (10): 1751-1763. SPE-14714-PA. http://dx.doi.org/10.2118/14714-PA.

14. Schlumberger. GHOST Gas Holdup Optical Sensor Tool. N.p.: Schlumberger, 2001. PS Platform. Schlumberger, June 2001. Web.

15. "Production Logging Flowmeter - Downhole Technologies GE Energy." GE Energy. N.p., n.d. Web. 12 Dec. 2014.

16. "Gas Hold-up Tool (GHT)." GE Energy. N.p., n.d. Web. 12 Dec. 2014. 17. "Enhanced Capacitance Water Hold-up (CWH)." GE Energy. N.p., n.d. Web. 12 Dec.

2014. 18. Aker Solutions, Statoil Pen Agreement for Wireline Tractor Services (Norway)."

Offshore Energy Today. N.p., n.d. Web. 12 Dec. 2014. 19. Aker Solutions. Wireline Tractor and Tractor Applications. N.p.: Aker Solutions, 2013. 9

Aug. 2013. Web. 12 Dec. 2014. 20. Fundamentals of Formation Testing. Sugar Land, TX: Schlumberger Marketing

Communications, 2006. Web 21. Surface well testing overview, Schlumbergers Course Material Presentation 22. www.mehranservices.com/index.php/services-products/81-well-testing 23. www.fujielectric.fr

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24. http://www.corelab.com/promore/intelligent-wells 25. O. Haldun Unalmis. Multiphase Flowmetering in Wells Wanted: Reliable & Accurate

Multiphase Flow Measurement in Intelligent Completions, Weatherford 26. www.weatherford.com/Products/Production/ReservoirMonitoring/DownholeOptical-

MultiphaseFlowmeter 27. S. Kimminau The impact of permanent downhole multiphase flow metering.

Schlumberger 17th World Petroleum Congress, 2002 28. 01-Introduction to Vx technology. Schlumbergers Course Material Presentation 29. SAGD Real-Time Well Production Measurements Using a Nucleonic Multiphase

FlowMeter: Successful Field Trial at Suncor Firebag. Schlumbergers technical paper, 2011

30. www.exprometers.com/Permanent_Clamp_on_Metering 31. www.exprometers.com/Multiphase_Flow_Meter 32. www.petromin.safan.com 33. API Recommended Practice 17A 34. Ove Jansen "Will subsea production make topside obsolete" Floating Production 2010,

FMS Technologiess presentation 35. www.tekna.no/ikbViewer/Content/798901/12 36. Trond Inge Ramsnes Subsea well intervention; Learning from the past planning for the

future. Statoils presentation, 2010

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2. Well production optimization Every company operating in oil and gas industry wants to get its revenue today, so its

ultimate goal is to have as high production rate as possible, of course taking into account the final recovery factor. And this problem can be divided into two subproblems: long term reservoir management and short term production optimization.[1] So well production optimization is the problem of daily well treatment in order to increase or maintain good production rate.

During production we face various problems which one should solve. Here we will discuss the following potential problems:

1) Water problem; 2) scale formation; 3) low permeability. As we begin to produce oil, water table level goes up and in the vicinity of the well water

coning problem takes place, leading to water production, which is unwanted. The same problem with gas interface, as we decrease the pressure in the reservoir, gas starts to expand and goes down to perforated zone, which is also unwanted. Because in oil and gas reservoir, firstly we have to produce oil, in order to avoid sharp pressure drop.

But sooner or later water reaches the production well and we start to produce more water than oil, we can observe it by WOR. As we see in the Figure 1, nowadays we produce a lot of water from hydrocarbon reservoirs, and this leads to our second problem scale formation.

Scale formation is one of the few problems that can smother a productive well within 24 hours. So it is very important to remove, predict and prevent such financial damage. Scale is an assemblage of deposits that cake perforations, casings, production tubing, valves, pumps and downhole completion equipment clogging the wellbore and preventing fluid flow. The scale forms either by direct precipitation from underground water, or as a result of produced water becoming oversaturated with scale components when two incompatible waters meet downhole.[2]

Another problem is the reservoir with low permeability or low fluid mobility. According to Darcys law:

=

low permeability causes limited production and sharp pressure drop near the wellbore and leads to flow restriction.

Well production optimization is the way one removes each problem by proper treatments. For example, to increase permeability, we do fracturing of the reservoir. There are also methods to treat with scale formation and water table shift problems. Principles of these methods are explained widely in the next sections.

Figure 1 - Water-Oil Ratio by regions [5]

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2.3. Assuring flow through tubular In this section we will talk about precipitation and deposition of solids in the tubular and

methods of fighting with it. Scales are precipitated from water, but there are also precipitations from hydrocarbons:

waxes, asphaltenes and hydrates. They usually cover scale thereby protecting scale from chemical treatments.

Formation of scales. The main idea in solving this problem is to identify the causes and locations of scale. The driving force for scale formation may be a temperature or pressure change, outgassing, a pH shift or contact with incompatible water. But its not always the case. The main cause of the deposition is nucleation processes:

1) Homogeneous nucleation the atom clusters form small seed crystals triggered by local fluctuations in the equilibrium ion concentration in supersaturated solutions. The seed crystals subsequently grow by ion adsorbing onto imperfections on the crystal surfaces extending the crystal size;

2) Heterogeneous nucleation crystal growth tends to initiate on a pre-existing fluid boundary surface. It includes surface defects such as surface roughness or perforations in production liners, or even joints and seems in tubing and pipelines.

Another cause to catalyse scale formation is a high degree turbulence zones. This explains why scale deposits rapidly build on downhole completion equipment. On the picture above we can observe where does scale forms in the tubing. [2]

Fighting with scale. After identifying, we have to remove it without damaging the wellbore, tubing or formation environment and prevent from reprecipitation. Fighting with scale costs a lot to industry and needs effective and fast methods. There are two approaches of scale-removal methods depending on the location of scale and its physical properties:

1. Chemical; a. hydrochloric acid (HCl); b. EDTA (ethylenediamenetetraacetic acid); c. U105;

2. Mechanical; a. mechanical cleaning; b. chemical cleaning; c. Jet Blaster tools.

Carbonate minerals are highly soluble in hydrochloric acid. But hard sulphates are not so easy, because the scale has a low acid solubility. Thats why hydrochloric acid is usually the first

Figure 2 - Scale in tubing [2]

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choice to treat with CaCO3 scale. But the rapid acid reaction hides a problem: spent acid solutions of scale by-products are excellent initiators for reformation of scale deposits.

The answer to this problem was ethylenediamenetetraacetic acid (EDTA). It dissolves and chelates calcium carbonate, breaking this reprecipitation cycle. EDTA treatments are more expensive and slower than hydrochloric acid, they work well on deposits that require a chemical approach. It is also effective in noncarbonate scale removal, e.g. calcium sulphate, mixtures of calcium-barium sulphate.

After, Schlumberger developed an improved EDTA-based scale dissolver, called U105. This dissolver was designed specifically for calcium carbonate, but also effective against iron carbonate and iron oxide scales. Other chelating agents have been optimized especially for barium and strontium sulphate scale.

There are also different types of mechanical methods of scale removal. One of the earliest scale-removal methods was the use of explosives. But this technique damaged tubulars and cement, and could not remove thick scale. Here comes impact bits and milling technology, which were developed to run on coiled tubing inside the tubular.

Fluid-mechanical jetting tools use multiple jet orifices or an indexed jetting head to achieve full wellbore coverage. These tools can be used with chemical washes. But this technique is effective only for soft scale, such as halite. Adding a small concentration of solids, 1-5% by weight, to a water jet can drastically improve its ability to cut through scale. It is called abrasive slurries method. But when scale is completely removed, abrasives such as sand can damage steel tubulars. So it was proposed to use new abrasive material called Sterling Beads abrasives. This material matches the erosive performance of sand on hard, brittle scale materials, while being 20 times less erosive of steel. The abrasive particles have spherical shape, a high fracture toughness and low friability.

And finally, universal scale-removal system is Jet Blaster tool, which has jet-nozzle characteristics optimized for use with Sterling Beads abrasives. This rotating jetting-head-based tool, combined with Sterling Beads abrasives, forms the basis of new system of coiled tubing-conveyed intervention services designed to remove scale in downhole

tubulars. It can be used in two techniques: 1. Scale Blasting technique; 2. Bridge Blasting technique.

Scale Blasting technique removes scale of any hardness without damaging the tubular. Bridge Blasting technique is used when scale deposits completely bridge tubular. [2]

Figure 3 - Jet Blaster tool

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2.2. Production zone selection As we said earlier, oil operating companies do not prefer to produce water. But there are

some waters that better than others. There are three terms describing water in the oil production: Sweep water water that comes from an injection well or an active aquifer that is

contributing to the sweeping of oil from the reservoir; Good water water that is produced into the wellbore at a rate below economic limit of

WOR; Bad water excess water that is produced above WOR economic limit. Here are some causes of bad

water (Fig.4): a. Casing, tubing or packer

leaks; b. Channel flow behind casing; c. Moving oil water contact; d. Coning and cusping; e. Gravity segregation etc.

The main solutions in these cases are to use

shutoff fluids or mechanical shutoff using plugs, cement and packers. [3]

Plugs can be used in the case when we have only one section or layer of production, and cement squeeze is used when we are producing from several layers.

Bridge plug is a downhole tool that is located and set to isolate the lower part of the wellbore. Bridge plugs may be permanent or retrievable, enabling the lower wellbore to be permanently sealed from production or temporarily isolated from a treatment conducted on an upper zone. They are installed by wireline or coiled tubing. [6]

Squeeze cementing is the process of using pump pressure to inject or squeeze cement into a problematic void space at a desired location in the well. Squeeze cementing operations may be performed at any time during the life of the well: drilling, completions or producing phases. Invariably, though, it is an operation undertaken to remedy a problem and presents the challenge of placing the proper amount of cement (or sealant) in the target location. Depending on the remediation need, squeeze cementing operations can be performed above or below the fracture gradient of the exposed formation (high pressure squeeze and low pressure squeeze, respectively). [4]

But for water coning problem these techniques dont work well. So there is another solution found. It is to perforate the water leg of the formation and coproduce the water to

Figure 4 - Water problems [3]

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eliminate the water cone (Fig.5). This low cost approach may increase water cut, but improves the sweep efficiency. [3]

Figure 5 - Fighting water with dual drains

Finally, if water problems are solved, one can make new perforations in order to increase production rate

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2.3. Fracturing The process of fracking produces fractures in the initially low permeable reservoir rock in

order to stimulate the flow of natural gas or oil towards the well, thus increasing the recoverable volumes. These fractures are initiated by different techniques, such as pumping large quantities of special liquids or gases at high pressure into the rock formation, using explosives, electricity and etc [7].

The very first fracturing technique, named the exploding torpedo, was discovered and then patented in 1866 by Col. Edward A. L. Roberts. An iron case, containing an amount of explosive, was lowered into the well close to the reservoir rock, where it was exploded. However, the first commercial application of what is nowadays known as hydraulic fracturing was conducted about hundred years later, in 1949 near Duncan, Oklahoma; and has been widely used ever since [11].

There are 4 main domains of fracturing [9]:

- Hydraulic fracturing (water-based, foam-based, oil-based, acid-based, alcohol-based, emulsion-based, cryogenic fluids such as CO2, N2, He);

- Pneumatic fracturing (gas fracturing); - Fracturing by explosives; - Other (thermal, mechanical cutting, and etc.)

Fracturing by liquids (or hydraulic fracturing) is by far the most efficient and developed fracturing method today (Fig.6). The fracturing fluids commonly consist of water, proppant and chemical additives that create and enlarge fractures within the reservoir. Different fluid compositions at their end determine different techniques of hydraulic fracturing based on the formation types. For example, acids are widely used in carbonate formations, and water with proppants in cataclastic reservoirs (shales, sandstones). The proppants - sand, ceramic pellets or other small incompressible particles are used to hold

open the newly created fractures. In addition, chemical additives support the process of fracturing by changing the pumping fluid and rock properties (the list of commonly used chemical can be found here: https://fracfocus.org/chemical-use/what-chemicals-are-used).

Nowadays, the process of hydraulic fracturing is a complicated process of several stages. The main steps are the following [8]:

Figure 6. A brief scheme of hydraulic fracturing [10].

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1. Injection of a prepad, a low-viscosity fluid used to condition the formation. It may contain fluid loss additives, surfactants, and have a particular salinity to prevent formation damage.

2. Injection of a pad, a viscous fluid with no proppants that initiates the generation of fractures. Main criteria high pumping pressure.

3. Injection of a proppant containing fracturing fluid. Proppants are needed to keep the fractures open and thus highly permeable.

4. Treatment with flush fluids, in order to clean up the formation. Main criteria high pumping rate.

Other than water-based hydraulic and acid fracturing, there are many techniques of fracking the reservoir formations. The most common techniques are listed in Table 1. Many methods are not included in the table, because currently they are only in their concept stage, and were not yet established as commercially rentable. Type of Fracking Advantages Disadvantages Foam-based fluids

Water usage reduced (or completely eliminated in case of CO2 based foams).

Reduced amount of chemical additives. Reduction of formation damage. Better cleanup of the residual fluid.

Low proppant concentration in fluid, hence decreased fracture conductivity.

Higher costs. Difficult rheological characterization

of foams, i.e. flow behavior difficult to predict.

Higher surface pumping pressure required.

Oil-based fluids

Water usage much reduced or completely eliminated.

Fewer (or no) chemical additives are required. Abundant by-product of the natural gas

industry. Increased the productivity of the well. Lower viscosity, density and surface tension of

the fluid, which results in lower energy consumption during fracturing.

Recovery rates (up to 100%) possible. Very rapid clean up (often within 24 hours).

Involves the manipulation of large amounts of flammable propane, hence potentially riskier than other fluids and more suitable in environments with low population density.

Higher investment costs. Success relies on the formation ability

to return most of the propane back to surface to reduce the overall cost.

Alcohol-based fluids

Water usage much reduced or completely eliminated.

Methanol is not persistent in the environment (biodegrades readily and quickly under both anaerobic and aerobic conditions and photo-degrades relatively quickly).

Excellent fluid properties: high solubility in water, low surface tension and high vapor pressure.

Methanol is a dangerous substance to handle: a. Low flash point, hence easier to ignite. b. Large range of explosive limits. c. High vapor density. d. Invisibility of the flame.

Emulsion-based fluids

Depending on the type of components used to formulate the emulsion, these fluids can have potential advantages such as: a. Water usage much reduced or completely

eliminated. b. Fewer (or no) chemical additives are

required. Increased the productivity of the well. Better rheological properties.

Potentially higher costs.

Liquid CO2 Potential environmental advantages: The main disadvantages follow from

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a. Water usage much reduced or completely eliminated. b. Few or no chemical additives are required. c. Some level of CO2 sequestration achieved.

Reduction of formation damage (reduction of permeability and capillary pressure damage by reverting to a gaseous phase; no swelling induced).

Evaluation of a fracture zone is almost immediate because of rapid clean-up. The energy provided by CO2 results in the elimination of all residual liquid left in the formation from the fracturing fluid.

the fluids low viscosity. Proppant concentration must

necessarily be lower and proppant sizes smaller, hence decreased fracture conductivity.

CO2 must be transported and stored under pressure (typically 2 MPa, -30C).

Corrosive nature of CO2 in presence of H2O.

Unclear (potentially high) treatment costs.

Pneumatic racturing Potential environmental advantages: a. Water usage completely eliminated. b. No chemical additives are required.

Potential for higher permeabilities due to open, self-propped fractures that are capable of transmitting significant amounts of fluid flow.

Limited possibility to operate at depth.

Limited capability to transport proppants.

Explosive fracturing Potential environmental advantages: a. Water usage completely eliminated. b. No chemical additives are required.

Minimal vertical growth outside the producing formation.

Selected zones stimulated without the need to activate packers.

Minimal formation damage from incompatible fluids.

Homogeneous permeability for injection wells. Minimal on-site equipment needed.

Can replace hydraulic fracturing only for small to medium treatments, i.e. the fracture penetration is somewhat limited.

Proppant is not carried into the fracture. Instead, propellant fracturing relies upon shear slippage to prevent the fracture from fully closing back on itself.

The energy released underground, albeit relatively low, could potentially induce seismic events.

Table 1. Main non-conventional methods of fracking [9].

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Well Productivity Optimization

There are many causes of flow restrictions that lead to additional pressure drop in the well bore, and thus reduce the productivity. And understanding these restrictions is the key feature to the treatment and optimization of the flow. Productivity itself is a complicated function of well geometry and properties of the porous medium. With time, many additional restrictors develop in the production point, which are needed to be taken care of. The main problems include [14]:

Migration of fine particles Change in wettability Swelling of clays Induced particle plugging Deposition of asphaltenes and sludge Emulsion Block Bacteria Water Block

All these problems arise from different operations like [12]: Drilling (filter cake, water block, swelling of clays, precipitation of salts,

slumping of sands, etc.); Completion and Workover (migration of fines to the formation from the cement

slurry, precipitation of solids from the cement, plugging by materials from wellbore fluids, improper perforation conditions, hydration and swelling of clays, etc.);

Stimulation (polymer invasion, emulsification, etc.); Production, water/gas injection, EOR (formation dissolution, fines migration,

solid invasion, sand influx, etc.). Thanks to the modern technologies, most of these formation and well bore damages can

be eliminated by a single piece of equipment, called the Coiled Tubing (CT). The name refers to a long continuous metal pipe, which is spooled on a reel for transportation. However, a fully functional CT unit is more than just a reel. The coiled tubing unit is a complete set of equipment, that can perform standard tubing operations in the field alone. The unit consists of the following elements (Fig.7)[15]:

Reel - for storage and transportation of the CT; Injector Head the driving force to insert and retrieve the CT, also has a pipe-

straightening unit; Control Cabin used for monitoring and controlling the CT; Power Pack - generates necessary power to operate the CT unit.

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Figure 7. Schlumberger CT unit [13].

This design of the CT is crucial and brings a lot of advantages over the other technologies.

The main distinctive features along with the drawbacks of the CT are given in the Table 2. Advantages Disadvantages

Deployment and retrievability while continuously circulating fluids;

Ability to work with surface pressure present (no need to kill the well);

Minimized formation damage when operation is performed without killing the well;

Reduced service time as compared to jointed tubing rigs because the CT string has no connections to make or break;

Increased personnel safety because of reduced pipe handling needs;

Highly mobile and compact. Fewer service personnel are needed;

Existing completion tubulars remaining in place, minimizing replacement expense for tubing and components;

Ability to perform continuous well-control operations, especially while pipe is in motion.

CT is subjected to plastic deformation during bend-cycling operations, causing it to accumulate fatigue damage and reduce service life of the tubing string;

Only a limited length of CT can be spooled onto a given service reel because of reel transport limitations of height and weight;

High pressure losses are typical when pumping fluids through CT because of small diameters and long string lengths. Allowable circulation rates through CT are typically low when compared to similar sizes of jointed tubing.

CT cannot be rotated at the surface to date. However, interest in rotating CT has been high in recent years, and several companies are actively designing equipment that will allow rotating of CT.

Table 2. Main distinctive features of the CT [12].

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2.4. Work-over The work-over is a process of performing major maintenance or repair works of an oil or

gas well. In most cases, this operation involves killing the well and the removal of the production tubing. This could be avoided by using coiled tubing, snubbing or slickline equipment at the early well service stages. However, if a complete treatment is necessary, a special equipment unit called the work-over rig is installed at the well [6].

The main causes of the work-over are given in the table below [16]:

1. Equipment failure Broken rod in pumping well (due to mechanical wear); Subsurface pump failure (due to physical wear of pumps moving parts); Leak in tubing (due to corrosion or mechanical stresses); Plug (due to accumulation of solids in the production string).

2. Wellbore problems Sanding Formation Damage Oil-Water Emulsions Corrosion

The processes of work-over differ based on the problem type. However, they all share the main steps, which are:

Shutting down the well; Preparation of the well-head; Tubing rig-up; Service equipment rig-down; Necessary works and restarting the well

by previous steps in inverse order.

A typical work-over rig consists of the following (Fig.17):

a wheeled truck; an extensible mast (tower) that is

connected by the pivoting assembly to the truck;

a remotely-controlled pivoting assembly that allows moving the mast from horizontal (travelling) to vertical (operational) position;

a remotely-controlled telescoping assembly that allows extending the mast from retracted (travelling) to extended (operational) position;

a remotely-controlled hoisting assembly

Figure 8. Work-over rig components [17]

33

to lift selected objects within the mast; a power supply (diesel engine); a work floor, a metal deck with a hole in the middle that allows to work above the

wellhead and the BOP; a tubing board, also known as the derrickmans working platform.

In addition, work-over rigs can be divided into classes based on their size and power (Tab.3).

Class II Class III Class IV Class V

2.6. References 1. L.A. Saputelli, S. Mochizuki, L. Hutchins, R. Cramer, M.B. Anderson, J.B. Mueller, A.

Escorcia,A.L. Harms, C.D. Sisk, S. Pennebaker, J.T. Han, A. Brown, C.S. Kabir, R.D.Reese, G.J. Nunez, K.M. Landgren, C.J. McKie, and C. Airlie. Promoting real-timeoptimization of hydrocarbon producing systems. In SPE Oshore Europe Aberdeen,September 2003.

2. Schlumberger, Oilfield Review Autumn 1999, Fighting Scale Removal and Prevention 3. Schlumberger, Oilfield Review Spring2000, Water Control 4. http://www.halliburton.com/en-US/ps/cementing/cementing-solutions/squeeze-

cementing/default.page?node-id=hfqela4e 5. http://www.ifpenergiesnouvelles.com/index.php/content/download/70601/1513892/versi

on/2/file/Panorama2011_11-VA_Eau-Production-Carburants.pdf 6. Schlumberger Oilfield Glossary. . 7. EPA." The Process of Hydraulic Fracturing. N.p., n.d. Web. 24 Nov. 2014.

. 8. Fink, Johannes Karl. Hydraulic Fracturing Chemicals and Fluids Technology. Waltham,

MA: Gulf Professional / Elsevier, 2013. Print. 9. Gandossi, Luca. "JRC Publications Repository." : An Overview of Hydraulic Fracturing

and Other Formation Stimulation Technologies for Shale Gas Production. N.p., n.d. Web. 29 Nov. 2014.

10. Granberg, Al. Fracking. Digital image. What Is Hydraulic Fracturing? N.p., n.d. Web. 29 Nov. 2014. .

11. "Shooters - A "Fracking" History." American Oil & Gas History. N.p., n.d. Web. 24 Nov. 2014. .

12. "PEH:Coiled-Tubing Well Intervention and Drilling Operations." PetroWiki. N.p., n.d. Web. 03 Dec. 2014. .

13. "CT EXPRESS Rapid-Deployment Coiled Tubing Unit." Schlumberger. N.p., n.d. Web. 03 Dec. 2014. .

14. Pandey, A. K. WELL STIMULATION TECHNIQUES. Rep. N.p.: n.p., n.d. Web. 2 Dec. 2014. .

15. An Introduction to Coiled Tubing: History, Applications, and Benefits // ICoTA, 2005 16. "Workovers." Workovers. N.p., n.d. Web. 07 Dec. 2014.

. 17. Ibarra, Santiago. Toy Workover Rig. Patent US 20120045964 A1. 23 Feb. 2012. Print.

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Contents1. Flow Dynamics and Production Monitoring1.1. Production vs Well & Surface Equipment1.2. Producing Interval Evaluation1.3. Well Testing & Monitoring1.4. Permanent monitoring1.5. Sub-sea well. Flow optimization1.6. Reference2. Well production optimization2.3. Assuring flow through tubular2.2. Production zone selection2.3. FracturingWell Productivity Optimization2.4. Work-over2.6. References