PAPER 2009-128

Oil Production Increase through an Automated Annulus Pressure Control System applied Extra-

heavy Oil wells in PDVSA, San Tome District.C. BRUNINGS

PDVSA E Y P

G. BECERRAPDVSA E y P

W. QUIJADAPDVSA E y P

Re field are located in the southern part of Anzoátegui state in eastern Venezuela, while bare field is located further south and is one of the first block of the Fiji region.

This paper has been selected for presentation and publication in the World Heavy Oil Congress 2009 Proceedings. All papers selected will become the property of WHOC. The right to publish is retained by the WHOC’s Publications Committee. The authors agree to assign the right to publish the above-titled paper to WHOC.

AbstractExtra- heavy oil wells in the Orinoco Oil Belt require

pumping systems, due to low reservoir pressure and high fluid viscosity. Pumping process reduces well flow pressure, originating gas liberation, increasing foam percentage in the heavy oil liquid phase. It reduces pump efficiency and makes impossible in many cases to increase oil production through a higher velocity, despite high dynamic fluid level.

Moreover well IPR curve does not show the common inverse relationship between fluid production and bottom flowing pressure, there is a sizable decline in production when the pressure is reduced far below the bubble point pressure.

A new technology that does not need rig intervention is applied from the year 2005. This technology optimizes well pumping efficiency through an automated annulus pressure control system; it also found an appropriate Pwf that maintains an automated differential pressure. During this time it generates stimulation around the pay zone by a pulsing effect improving the gas free liquid level over the pump. Present results show an increase of an average of 60 percent additional oil production and water cut reduction of 25 percent.

The purpose of this paper is to present the results reached at the present including comments of the project in

development giving explanations more accuracy about reservoirs performance with regard to water cut reduction stabilization

IntroductionOil reservoir studies have proven the existence of very large

recoverable amounts of oil in place in the Orinoco Oil Belt, nonetheless, it is of paramount importance to improve the production rates of those wells whose high GOR and high water cuts, and hence low oil production rates, makes them unprofitable to operate. A large number of these reservoirs are bordered by active aquifers, and the existing producing wells show waters cuts above 40%. On the other hand, and due to increased bottom hole gas production, the volumetric efficiency of downhole pumps are continually decreasing; with a subsequent decline in oil production. In order to solve these oil production deficiencies, new technologies, to enhance the artificial lifting of oil through an appropriate management of

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multiphase flow, have been evaluated and applied. In this direction, personnel at the San Tome District prompted the development of an automated system for the enhancement of oil well production. The success of the system depends on the automatic and sustained control of the annular space (casing-tubing) pressure, and consequently the bottom hole flowing pressure. It has been numerous observations of casing pressure fluctuations in acoustic fluid level readings that seemed to be in the regions of reduced water cut. Since the casing is closed during acoustic fluid level testing, the ripple in casing pressure must be associated with fluctuation in gas flow from the reservoir. In theory, those fluctuations could be caused by the slug flow of oil into the casing. Recent real-time measurements of water cut have detected substantial fluctuations that suggest the reservoir is delivering oil and water in a slug flow fashion. The technology uses a high precision casing pressure sensor and digital signal processing to detect ripples in casing pressure that can be used as an optimum pressure control set point.

Heavy oil can have foamy columns of fluid in the casing that causes interference with pump performance. Increased casing pressure can collapse those foamy columns and help reduce gas locking of sucker rod pumps and reduce gas interference on ESP systems. The increase casing pressure also stiffens the spring constant of the casing gas column which could have a stabilizing effect on down hole pressure.

Traditional IPR curves describing well performance show a generally increasing flow of oil with decreasing well flowing pressure. Wells with high water cut will generally show a relatively straight line relationship between fluid flows and draw down pressure. Wells with high oil cut will show a reduced rate of increased production due to the breakout of gas.

The treatments to prevent or control unwanted fluid production are associated to high costs which include the use of service rigs. Low pressure at the sand face can cause gas and/or water coning. Increasing that well flowing pressure without the use of service rigs, would reduce the water influx and keeps more gas in solution. Keeping gas in solution has a beneficial effect on oil flow by reducing its viscosity and also it is presented the hysteresis phenomenon in the permeability and capillary pressure curves which reduce the water and gas production, so this technology regulate the casing pressure to an optimal value that produce an increase oil production.

In San Tome District, 73% of the crude oil production is obtained by mechanical pumping methods (66% of the wells). The wells are checked on a daily basis and a diagnosis of the pump efficiency, with respect to gas handling, is performed. Due to their gas and water production characteristics, and their mechanical configurations, many of those wells with bottom hole pumps are candidates for the application of the technology presented in this paper.

In this paper are presented the applied procedures, and their results, as well as the studies under development.

Theoretical Considerations

Technology of Annular Pressurization

Reservoirs fluids drainage is characterized by a continuous increase of the water-oil ratio, caused by the invasion of water into the oil drainage area, due to the vertical permeability, the anisotropy of the formation, the difference of viscosities, the decrease in pressure, etc. This produces in the reservoir close to

the wellbore area a vertical flow that deforms the water - oil interface, with a characteristic pattern for each well. The irregular advance of the water prevents the flow of oil from the formation towards the wells, and at the same time it encourages the production of water and therefore it causes low recoveries of crude oil, and an excessive spending of reservoir energy per barrel of net crude oil produced, which in turn shortens the productive life of the reservoir and raises the costs of production.

On the other hand, large quantities of produced free gas affect the volumetric efficiency of the bottom hole pump. Therefore, if there is not a mechanical device installed at the bottom of the well, such as a gas separator, the efficiency of the pump will continually decrease. If solution gas is present in the pump, the pump will normally operate with greater efficiency. Traditional operation practices involve the continuous displacement of the gas within the annular space (casing – tubing). However, the annular pressurization technology focuses in keeping an optimum differential pressure in the annulus (Figure 1), where favorable changes of relative permeabilities, GOR and water cuts occur, with a change in fluids mobility as the gas either stays in, or enters into solution by pressurization.

Figure 1. Effects of the annular pressurization.

Fundamentals of Reservoirs

Foamy Oil

According to lab test experiments (1,2), some heavy and extra-heavy viscous crude oils such as those present in the Orinoco Oil Belt have a foamy behavior (Figure 2), in which the gas bubbles are entrained in the oil due to high viscosity, low diffusion coefficient and asphaltene content.

As pressure is being lowered, reaching the pseudo bubble point large quantities of gas are produced thus an increment of the gas oil ratio is experienced.

This foamy oil with gas bubbles trapped in the crude generates gas and fluid batches. Based on these premises different types of equipment were designed for production optimization.

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Figure 2. Foamy oil behavior. Well MFB-91, Orinoco Oil Belt(2).

The Phenomenon of Hysteresis

This phenomenon (3) takes place in the porous media when occurs a direction change in the flow according to the following explanation (Figure 3).

Figure 3. Hysteresis of permeability curves.

Water - oil

Based upon the results of core analysis available for this reservoir, and the Krw-Kro curves, the wetting phase is oil (oil wet), (3). In this case, during the production of wells before annular pressure control, the displacement of the oil (wetting phase) by water (non wetting phase) was of the drainage type. The water moves through the largest porous channels of the rock, and oil through the smallest ones. This preferential flow generates channeling of the water. The preferential movement of the water is aided by the high mobility water-oil ratio (Krw*µo)/(Kro*µw), due to the high value of the numerator (Krw*µo). During the bottom hole pressurization process (Pwf increases by properly managing the annular pressure) water tends to recede in the porous media close to the well, therefore, the process of displacement is reversed from drainage to imbibition. This reduces the Krw, and the same time occurs a µo reduction by the partial entry of free gas into solution until the oil is saturated at the new pressure around the well; these two phenomena contribute to the reduction of the Krw*µo product, and therefore to the reduction of water cuts.

Gas - Oil

Another benefit resulting from the application of the pressurization process is the increase of the saturation of residual gas (or gas trapped by the wetting phase, in this case by the foaming character of the oil), during the stage of production with the annulus and bottom well pressurized.

Also, the phenomenon of gas - oil hysteresis leads an increase of the residual gas and a reduction of the GOR. (Figure 4).

Figure 4. Effects of casing pressure control on the reservoir behavior near the wellbore.

Description of The Annular Pressure Control Technology.

The annular pressure control technology is basically a technique for the optimization of crude oil production from oil wells. It consists in the establishment of artificial lift working conditions under a high annular pressure regime. This means that each well will operate under its own working scheme (let it be slow, moderate or fast).

The equipment installed in the Orinoco Oil Belt (Figure 5) is constituted by three main components: 1.- The Vector Drive: which controls and optimizes operating variables of this process. 2.- The hardware: Uses a system to capture well information in the annular space. 3.- The software: which processes the information and computes, through mathematical models, the optimum Pwf, where favorable changes are observed in water-oil ratios and/or GORs.

Figure 5. General setup equipment, connections area.

Additionally it is used an electronic water cut measurement through multiphase equipment to obtain the production test and to validate the water cut more accurate, since it is difficult to establish an average value by a traditional continuous sampling method in heavy crude oil.

Well Selection CriteriaFor the successful application of the technique, the selected

wells should follow certain specifications, since the technique is not universally applicable. It applies for any type of crude oil, however, best results are attained in medium, heavy and extra-heavy oils; independently of the pay formation depth.

The technology is applicable in wells producing below bubble point conditions, with either PCP or ESP or MP pumping units, nonetheless, each of these artificial lifting methods requires of a specific procedure for its application, in

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PSIA

MULTIVARIATE SENSOR PRODUCTION LINE

CONTROLLER (STAND ALONNE)CONTROLLER+VFD (INTEGRATED)

VALVE+MULTIVARITE SENSOR PRODUCTION CASING

HOSESINPUT/OUT PUT LINE

DRAINAGEIMBIBITION

RESIDUAL NON-WETTING PHASES

SATURATION

INTERSTITIAL WETTING PHASES

SATURATION

WETTING PHASES SATURATION, % PV

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TIV

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AB

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order to increase oil production by the control of the optimum bottom hole flowing pressure.

The following steps should be followed for the appropriate study and application of the technology:

A.- Revision of the existing surface conditions and bottom hole data gathering.

B.- Measurement of fluid levels in the production casing, utilizing acoustical devices, to detect and quantify the amount of gas generated through the annulus and the pump intake pressure (PIP).

C.- Installation of the equipment. It is important to make production tests for each well, prior to the application of the technology, for its certification and/or validation, since these tests will be used for future reference and comparison with those obtained after the technology has been applied.

Finally, a multiphase flow or water cut measuring device should be available for the constant monitoring of the technology implementation.

Investigation Methodology and Working Procedures

The present study has been conceptualized as a field and engineering investigation and has as its main objective to show the changes that take place in the fluids, and also at reservoir level, when the Annular Pressurization Technology is applied. This technology consists in controlling annular pressure by increasing it until an optimum bottom hole flowing pressure (Pwf) is reached. This process would allow to maintain such a production regime that will keep the gas in solution at the entry of the bottom hole pump, increasing the pump efficiency and the water cut ratio is kept stable, also in some cases, a considerable reduction of this parameter and therefore an improving the crude oil flow at the near wellbore area.

The established methodology is as follows:

Phases of the Investigation

Field

• Programming the annular pressurization tests.• Making the tests.• Qualitative analysis and quantitative evaluation of the

results.

Engineering

1. Conceptualization of the physical phenomenon of production enhancement.

2. Construction, testing and matching of the well and reservoir models with the production behavior observed prior to application of the annular pressurization.

3. Integration of those models.4. Matching the results obtained from the annular

pressurization tests.5. Conclusions and Recommendations. In order to develop the investigation methodology, and to

reach the main objective of this study, the following working program was established:

Working ProgramMultiphase flow Interpretation (construction of Multiphase

Model).1. Collecting of pressure and production tests data.2. Calculation of Pwf.3. Simulation and adjustments of the multiphase model.Integrated Simulation of the Pressurization Technology

ResultsIntegration of the Reservoir/Well/Surface Facilities network.

Development of the Reservoir Simulation Model.

A simulation model for the U1,3/MFB–53 reservoir was built by PDVSA, with 397 wells and 254215 active cells. Simulation runs were made for the 1981- 2009 period in order to determine its characteristics, and pressure and production history matching levels.

A section (window) of the south-western area of the reservoir, which includes the MFB–398 and the MFB–415 wells, was selected to simulate the pressure decline and the water and gas production history of these wells.

The window area was composed by a mesh of 25 x 17 x 38; 16150 cells (10341 active cells). It includes 13 wells (11 horizontal wells and 2 vertical wells, seven (7) of which have been subjected to alternate steam injection processes) (Figure 6).

The window model has already been initialized. Presently work is being done on a numerical simulation for the dynamic evaluation and field application of the technology and for predicting the future behavior of the wells under tests, while maintaining functional the pressure control equipment.

The two horizontal well models will be built with a fine mesh around the well bore, in order to observe, with greater details, the variations in saturation and pressure. At this time, production and pressure history matching runs are being made.

Figure 6. The Window Area, Grip Top, layer 4

Petrophysical ModelDue to the large planar extension of the U1,3/MFB–53

reservoir, a detailed petrophysical study, based upon two formation cores analysis and well logs from the reservoir, was made. Capillary Pressure (Leverett´s J Function), Relative Permeabilities, type of rock, and porosities were evaluated. These parameters were utilized for the construction of two well

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models, to simulate the production behavior of the wells MFB–398 and MFB–415, during both: the stage without pressure control and the stage under the application of the annular pressurization technology.

Multiphase Flow Model in the WellMultiphase flow in the well was simulated utilizing nodal

analysis techniques as follows:Select empirical correlations for calculating fluid properties

at temperatures different to those at reservoir level. These correlations were selected after fluid properties from PVT analysis were matched.

Match the dynamic temperature profiles inside de production tubing, determining a total heat transfer coefficient U (BTU/hr.ft2.ºF).

Match the dynamic pressure profiles inside the production tubing, by means of a sensibility analysis on the multiphase flow inside pipes, in order to select and adjust the most suitable correlation for simulating the behavior of such flow in the well.

Once the multiphase flow correlation has been selected, the well production capacity before and after annular pressure control, is matched.

Analysis of Results

Field resultsThe annulus pressure control technology has been applied in

the Wells of the Orinoco Oil Belt since 2005 year until now. So far have been installed equipments in 25 wells of the eastern of Venezuela; mostly of them with satisfactory results. Based upon the achieved results, new equipments are being installed on 14 wells on the Bare field of San Tome District.

Figure 7. Well performance, production efficiency

The effect of foamy behavior on the Orinoco oil belt can be

seen in the figure 7, observing the production efficiency performance in which, a maximum production rate is obtained at certain PIP and frequency, and the production decreases as the intake pressure goes down (600 psi), due to the gas liberation at the pump, lowering its efficiency.

The foamy oil with gas bubbles trapped in the crude generates gas and fluid batches (see red line for gas and green line for fluid on Figure 8. This graph shows production and gas

behavior every 30 minutes through a multiphase production separator.

The production performance, shows that is difficult to maintain the oil production rate with a given available pressure, drop and have been improved by applying the Annular Pressurization Technology, as we can see below

Lately production test have been done in the Wells MFB-398, MFB-415 and MFB-460, which show the performance of these Wells under pressure control versus no pressure control.

Surface direct logging of the line temperature and casing pressure parameters were recorded by electronic sensor and compared versus the same parameters at the inlet pump. The Figure 9 shows the variable cyclic effect recorded at the well surface, which appears being recorded approximately five (5) minutes delay at the pump intake. The cycle length (3 minutes) at the down hole is shorter than the cycle at the surface.

The increase casing pressure also stiffens the spring constant of the casing gas column, observing its effect on the transmission of pressure fluctuations to the down hole pressure.

The Figure 10 shows an inverse relationship between the casing pressure and the line temperature. This behavior can be understood as a change on the ratio of the produced fluids (oil and water). On the Figure 11 is observed a similar behavior between the pressure intake pump (PIP) versus fluid temperature.

Besides, the increase on the fluid temperature is related to the increase of the water cut.

On the Figure 12 is observed that, while the annular pressure is increased the water cut decrease.

The average value of the readings on each of the above figures represents the optimum working condition. An example of these data for the well MFB-398, are shown in the Table 1.

Table 1. Production test, well MFB-398.

The figures 21 to 25 show production performance of the wells MFA -70, MFA -241, MFB-386, MFB -398 and MFB-460 respectively which are presented in the appendix.

Simulation resultsSimulation of field test results is currently being done. First,

a petrography review of the window area, where test wells MFB-415 and MFB-398 are located, was made. Then, a multiphase analytical model was built including the simultaneous flow of oil, water and gas, from the reservoir to the well, and the effect of annular pressurization on the bottom hole flowing pressure. Finally, a black oil simulator is being run, for the window area, to determine the effects of the pressurization, around the well bore vicinity, on the water cuts a gas-oil ratios. Additionally, INTEVEP (a research subsidiary of PDVSA) is investigating the effect that the observed down hole flowing pressure variation pattern is having on the physicochemical equilibrium at pore level; due to changes in the fluid / fluid – fluid / rock interactions, for several heavy and extra-heavy oil sandstone reservoirs, with different reservoir quality, because of natural adverse flow conditions to the oil

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DATE BPDPIP

(PSIG)Pwf

(PSIG)BOPD BWPD %Bs&W CONDITION

15-Jul-2009 92 319 411 28 64 70 No control pressure12-Aug-2009 95 329 429 28 67 70 Under control pressure5-Sep-2009 88 339 442 38 50 57 Under control pressure7-Sep-2009 87 356 447 57 29 34 Under control pressure

MFB-398

pattern due to the different components in the heavy and extra heavy oils in situ.

Petrophysical Characterization of Window Area.

This characterization was made based upon core analysis and well logs from wells MFB-391, MFB-398 and MFB-415. Petrophysical parameters such as K (absolute permeability), Swirr (irreducible water saturation) and Pc (water-oil capillary pressure) were obtained from correlations built from core analysis results. The results show a high degree of uniformity (Lorenz´s Graph, Figure 13) for the unconsolidated sand near well MFB-391. Also, the Winland´s Graph (Figure 14), with K-Ø data from wells MFB-398 and MFB-415, shows that the rock is between a mega and of a macro superior type.

Figures 15 and 16 show the water-oil capillary and relative permeability curves. The capillary curves illustrate little dispersion (high uniformity) and a wide transition zone. The water-oil permeability curves show that the permeability to oil is greater than that to water, for water saturations below 37%; this shows that water flows more rapid than oil in the porous medium.

Multiphase Model.A multiphase model was built to match the current behavior

of wells subjected to bottom hole pressurization control. To estimate the changes, with pressure and temperature, of the oil, gas and water properties, well known correlations were used after matching available PVT analysis (U1,3 Reservoir /MFB-53). The petrophysical properties, for the flow from the reservoir to the bottom hole node, were taken from the previously shown petrophysical characterization.

The influx behavior curve (IPR) was determined from field tests (Test point data). It should be pointed out that for each test the bottom well flowing pressure (Pwf) was estimated from its respective pressure intake pump (PIP) utilizing the adjusted Hagerdon and Brown correlation.

Figure 15 shows the IPR curves for oil-water and total liquid of the well MFB-398 before the control pressure test. It can see that for Pwf = 420 psig the production rate were:

Oil 28 bpdWater 68 bpdComposite 96 bpdWater cut 70 %

Figure 16. Nodal analysis of well MFB-398, before pressure control test.

After the pressure control test the Pwf increase to 447 psig and the production flow rates change increasing oil flow rate and decreasing water flow rate as is shown in Figure 16.

Oil 57 bpdWater 29 bpdComposite 86 bpdWater cut 33.8 %

Figure 17. Nodal analysis of well MFB-398, after pressure control test.

As it is well known, the IPR curve represents the fluid flow capacity of take from the pay formation. The improvement in the oil IPR is due to the decrease of the water-oil mobility ratio (Krw*µo)/(Kro*µw). This phenomenon occurs by the pressurization of the formation near the wellbore which reduces the water saturation, the water relative permeability and the oil viscosity.

Besides, the results show that the oil IPR curve for MFB-398 well with no pressure control (Figure 16) moves to the right (Figure 15) with the increment of the well bottom pressure. This positive change of the IPR produces an increase in oil flow rate and a decrease in water cut. This changes is supported by the positive effect of the dispersed gas in the oil mixture which increments the oil mobility, also the difference on water-oil mixture density increase which reduces the water saturation and therefore increases the oil saturation and the relative permeability to oil. This behavior is according with research done by Patil (7).

Numerical SimulationA numerical simulation model was built for a window area

of the south-western zone of the reservoir. The mesh has 10341 active cells (25*17*38). The cell saturations and pressures for the initialization of the window model were taking from a run (1981-2009 period) of the hole reservoir model (254215 active cells). At it is seen in Figure 18 the pressure at year 1995 in layer 22 are in the range of 1181-1141 psi, close to the bubble point pressure, 1160 psi. The fluid properties of oil and gas were taken from the PVT analysis of well MFB-91 (5).

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Figure 18. Pressure initialization of the window model. Year 1995 and layer 22.

The water influx into the window area was simulating with bottom aquifer. It is considered that the water enters vertically in the reservoir from bottom water zones and flows to the top by the high permeability of unconsolidated sand.

Presently work is being done on match very carefully the water and free gas flow around the MFB-415 and MFB-398 wells which allow the future prediction the dynamic evaluation and field application of the casing annulus pressurization and the future behavior of the wells.

Up to now, good results have been obtained in the match of oil and water production of the wells MFB-398 and MFB-415. The Figure 19 show the excellent follow up of MFB-398 cumulative oil by the black oil simulator.

The water cut was good match in some periods of the well life. From year 2008 it can seen that the high water cut (60%) is very good reproduced showing that the water movement near the wellbore is good simulated. Similar results are illustrated by the cumulative water curves in Figure 20.

To achieve the water production match it was necessary simulate the effect of the dispersed gas in the oil which reduces the viscosity and density of the foamy oil mixture (6). Beside, the increment of mobility of the oil by viscosity reduction, the difference on water-oil mixture density increases which reduces the water saturation and the water mobility around the wellbore.

Conclusions• The field results have shown an average increase of

60 percent in oil production and a reduction of 25 percent of water cut.

• A variable cyclic effect has been recorded at the well casing surface, it is registered aproximately five (5) minutes delayed at the pump intake. The cycle length (3 minutes) at the down hole is shorter than the cycle at the surface.

• It has been observed an inverse relationship between the casing pressure and the line temperature, this behavior can be understood as a change on the ratio of the produced fluids (oil and water).

• The results show that the oil IPR curve for MFB-398 well with no pressure control moves to the right with the increment of the well bottom pressure. This positive change of the IPR produces an increase in oil flow rate and a decrease in water cut.

• There is a tendency to reduce the water cut in these wells, the theory behind it is the phenomena of imbibition and drainage of the oil phase, which increases the critical gas saturation and the foamy oil behavior produces an increment of the effective permeability at the oil phase thus reducing the effective permeabilities to gas and water, all this is under investigation.

• The Lorenz and Winland graphs of zones near wellbore of wells MFB-391, MFB-398 and MFB-414 show two rock types: Mega and superior macro with little heterogeneity.

• The capillary pressure of the formation shows a wide transition zone that help the annulus pressurization effect to reduce the water cut and to increase the oil flow rate.

• It was possible to match the annulus control pressure results of well MFB-398 with nodal analysis.

• The improvement in the oil IPR observed is due to the decrease of the water-oil mobility ratio near the wellbore (Krw*µo)/(Kro*µw).

• The numerical simulation of the test (window area) have allowed to match the water flow near the wellbore of MFB-398 and MFB-415 wells which will allow the future dynamic evaluation of annular pressure control test.

ACKNOWLEDGMENTSSpecial thanks to Dr. Gonzalo Rojas, and all investigative

team assigned by PDVSA to this work.

REFERENCES1. OTERO, C. et al. Foamy Oil: Determination of

Production mechanism and thermal effect over It . Paper UNITAR, 7th conference, 1098.040 in proceedings

2. BRUNINGS, C. New Technologies In Artificial Lift And Well Completions Applied In The Extraheavy Crude Oilfields In Pdvsa Eastern Division, The 1st World Heavy Oil Conference & Exhibition Heavy Oil—The Future of Global Energy Beijing, China November 2006. SPE 2006-772

3. AHMED, T. Reservoir engeniering handbook (2a ed.) Woburn, massachusells. beller-worth-helnemann, gulf professional publishing, 2001.

4. CORE LAB, Estudios de las Propiedades de la Roca, para PDVSA, Pozo MFB 627, Venezuela, Febrero 2005.

5. CORE LAB, Análisis PVT, Pozo MFB-91 para MENEVEN, Venezuela Mayo 1983.

6. SMITH, G.E. Husky oil operation Ltd.Fluid Flow and Sand Production in Heavy oil Reservoirs under Solution gas Drive. California Regional Meeting, Oakland, California. SPE 1986-15094.

7. PATIL, B. Gas interference Effect on IPR Curves, Master´s Thesis, Texas Tech University.2004

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Figure 8. Gas and Fluid Batches

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Figure 9. Pressure Behavior, well MFB-398

Figure 10. Casing pressure and line temperature.

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Figure 11. Pressure sensor, well MFB-398.

Figure 12. Annular pressure vs % Wc

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Figure 13: Lorenz graph, well MFB-391.

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Figure 14: Winland graph, wells MFB-398 and MFB-415.

Figure 15: Average capillary pressure curve.

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Figure 16: Water-oil relative permeability curves.

Figure 19: Match of oil production, MFB-398 well

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Figure 20: Match of water cut, MFB-398 well

Figure 21: MFB 460 Well Result

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Figure 22: MFB 398 Well Result

Figure 23: MFA 70 Well Result

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Figure 24: MFA 241 Well Result

Figure 25: MFB 386 Well Result

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