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By: J F Lea, PLTech LLC, David L. Divine, P.E. Wood Group ESP, & Lynn Rowlan, Echometer Co.

Introduction:
The electrical submersible pump system has been developed over the years by Engineers and scientists involved in metallurgy, hydraulics, electronics, heat transfer, plastics, many aspects of mechanical engineering, and other disciplines. It is not practical to outline all of the many aspects of the system in the short introduction section. Instead, the major components are introduced.



Overview:
The pump assembly is hung on the tubing with the electric cable banded to the outside of the tubing from surface to pump. The equipment is arranged from top to bottom with the pump first, with the gas separator below, then the seal section, followed by the motor. If a downhole pressure sensor is used, it is hung at the bottom of the motor. ESP's are thought of as high volume lift perhaps producing -20,000 bpd at 4000' down to -5000 bpd at 10,000' depending on many factors, but low volume (-100 bpd) stages exist.

Motor:
The electric submersible motor is a two-pole, three-phase, squirrel cage induction type. The motor runs at a nominal speed of 3500 rpm on 60 Hz frequency and 2900 rpm on 50 Hz. The motor is filled with a refined mineral oil to provide dielectric strength, lubrication of bearings and thermal conductivity. The thrust bearing of the motor carries the load of the rotors. The electrically nonconductive mineral oil lubricates the motor bearings and transfers heat in the motor to the motor housing. Heat from the motor housing is in turn carried away by the well fluids moving past the exterior surface of the motor. For this reason, the motor should not be set below the point of fluid entry unless some means of directing the fluid by the motor is utilized. Typical nominal motor diameters of equipment may be: (a) 3.75", (b) 4.56", (c) 5.402, 5.44", 5.62", and (d) 7.38" for various casing sizes. Some motors are offered with somewhat different diameters and some manufacturers do not carry some of the diameters indicated. Some Motor construction may be a single housing or several "tandems" bolted together to reach a desired horsepower rating. Motors range in horsepower from 5 to 1000 hp and larger.

Pump:
The electric submersible pump is a multistage centrifugal type. The type of stage used determines the approximate design volume rate of fluid produced but as the fluid compresses, each stage will have progressively less volume to handle. The number of stages determines the total head designed for and the motor horsepower required.

The usual materials used in manufacturing an impeller are Ni-Resist with some options for sand handling. Diffusers are typically manufactured of Ni-Resist. The standard shaft material is K-monel. Optional, high-strength shaft materials are Inconel and Hastalloy. Bolt-on heads and bases make it possible to vary the capacity and total head of a pump by using more than one pump section. However, large capacity pumps typically will have integral heads and bases. The nominal outside diameter of a pump will range from 3.38" to 11.25" but 7.62" to 8.38" could be largest oil well applications.

Seal Section. Protector, Equalizer:
The motor protector's primary purpose is to isolate the motor from the well fluid. There are, in general, two types of industry protector or seal section designs although there are specific differences from one brand to another. One type uses a positive bag seal and the other type uses a labyrinth or tortuous path. The "positive seal" design incorporates a fluid barrier bag to allow for thermal expansion of the motor fluid yet still provided isolation of motor fluids from wellbore fluids. The "labyrinth path" utilizes differential fluid specific gravity to prevent well fluid from entering the motor. This is accomplished by paths where the motor fluid is allowed to expand to displace more or less of the wellbore fluid as it expands through a tortuous path at an interface near the top of the protector. There are usually several "labyrinth paths" in one protector and more could be added by placing protectors in series. Normally the bag type positive seal protector is backed up with "labyrinth paths" so that bag failure is not necessarily catastrophic.

The protector or seal section performs four basic functions. These are: (1) It connects the pump to the motor by connecting the housing and drive shaft; (2) Houses a thrust bearing to absorb pump shaft thrust (if present); (3) Isolates the well fluid from the motor while still allowing pressure equalization between the wellbore and the oil-filled motor; and (4) provides for thermal expansion of the motor oil due to heat generated by the motor during operation and thermal contraction of the motor oil following pump shutdown/startup.

Gas Separator:
The gas separator is installed between the protector or seal section and the pump. Its purpose is to separate a significant portion of any free gas in the produced fluid and provide a fluid intake section for the pump.

There are two major types of gas separator designs - the static type and the rotary type. The static type reverses the fluid flow direction within the housing but the use is not as frequent now. At this point of low pressure there is gas separation. Any gas remaining in the fluid is separated by the pickup impeller which causes a vortex. The vortex allows the gas and fluid to separate. The separated gas is vented to the annulus and the higher density fluid flows into the first stage of the pump.

The rotary type design utilizes a rotary inducer/centrifuge to centrifugally separate the gas and produced liquids. The gas/fluid mixture initially enters the intake ports and moves into the inducer. This increases the pressure of the fluid and moves it through the transition section into the centrifuge. In the centrifuge the fluid is forced to the outside and gas rises through the centrifuge and flow divider into the crossover section. Here, the gas vented into the annulus and fluid is directed into the first pump stage. At present three (four in the near future) manufacturers are producing this type of separator. A "Vortex" separator may have a smaller paddle wheel at the bottom of a chamber where gas and fluids can swirl before exiting the separator.

Special stages are offered by some manufacturers when there is no path for separated gas. The special stages mix the gas and fluids and some are more proficient in producing head in the presence of high gas content.

Pressure Sensing Instrument:
The instrument has two major components - a surface readout unit and a downhole pressure and temperature sensing instrument. The downhole sensor is bolted to the base of the motor and sends a "ghost" signal to the surface unit through the motor windings and power cable as opposed to older designs requiring an extra "I" wire. One readout instrument alternates pressure and temperature readings on a 20-second interval. Other downhole instruments including intake and motor winding temperature. Other types of instrumentation are available.

There are many factors involved in operating ESP systems to lift a field. Below is an outline covering many of the aspects to be aware of when operating ESP's.

Outline of Factors for Good ESP Operations:

1) Well Data for Design and Operation:
i) Well tests
ii) IPR data
iii) Temperature and fluid properties
iv) Harsh conditions present?
(a) Sand
(b) Scale
(c) H2S, CO2
(d) Viscosity, emulsion
(e) High Temperature
(f) High gas production with the liquids
(g) Deviation
(h) Other?
v) Well Profile
vi) Tubulars
vii) WHP
viii) HZ of power supply available
ix) VSD part of installation?

2) Select Target Production:
i) AOF of well
ii) Bubble point
iii) Produce above or below bubble point
iv) Target production

3) Equipment Design:
i) Determine TDH
ii) Select type of pump and calculate number of stages
iii) Intake: Standard or gas separator
iv) Protector/Seal/Equalizer
(a) Bag/s
(b) Labyrinth sections (*)
(c) Tandem protectors?
v) Motor, type, HP
vi) Downhole instrumentation
vii) Cable: round / flat, size
Bands or cross coupling protectors
viii) Well head feed through type
ix) Control panel: Standard or VSD
x) See API RP 11S4 Recommended Practice for Sizing & Selection of ESP Installations

Example Simple Conceptual Design:

Consider the following data for design purposes. More detailed data would be required for actual application design:

IPR:
SIBHP: 2900 psi
Test Rate: 4000 bpd
Test Pressure on Perforations: 400 psi

Little gas
Perforations Depth: 6500 ft
Pump Depth 6000 ft
Casing: 5.5 inch
Tubing (to be determined but for 4000 bpd should be 3 ½, 4 or 4 ½ inch approximately)
WHP: 100 psi

Consider combination of water and oil such that the combined SpGr is 0.9. Approximate using volume of liquids do not change with down hole pressure and temperature. This is not true of course but approximately true if high water cut and little gas. This assumption allows a simple design example. For more and more gas and oil with water, this would be less and less true.

Power supply is 60 HZ. Use the above pump performance curve for this example.

Target rate: 4000 bpd

The pressure at the perforations is 400 psi. Consider the casing flow to the pump intake has little friction.

The pump intake pressure, PIP, is 400 psi – 500 ft ( .9*.433 psi/ft) = 205.15 psi.
For tubing flow to calculate the discharge pressure, consider tubing is selected such that friction pressure is 2-5% of the tubing pressure drop. This is typical for design of ESP. For this design use 3% for friction pressure drop.

Discharge pressure = WHP + .433(.9)(Depth)(1.+ % Friction) =
= 100 + .433(.9)(6000)(1. + .03) = 2508.3 psi

Then the TDH or total dynamic head is : TDH = (Pd – PIP)/( (.433)(.9))
= (2508.3-205.15) / ( (.433)(.9)) = 5901 ft

From the above performance curve read about 43.5 ft / stage.

Then the number of stages required is:
* Stages = TDH/ (head/stage) = 5901/43.5 = 136 stages

The HP required from the motor would be:

(* Stages) ( HP/Stage) (SpGr) = 136(1.95)(.9) = 238.7 HP
A larger somewhat de-rated motor would normally be selected for application



To complete the design, a cable would be selected (normally with no more that 30 V/1000 ft voltage drop), a switch board or VSD would be selected, and use of tubing for this design should be such that the pressure drop due to friction would be about 3% of the total tubing pressure drop. Other hardware would be ordered.

For heavy oil viscosity correction factors would come into play. For free gas at the pump intake, the gas would become part of the volume digested by the pump and the gas would also reduce the effective SpGr of the mixture. For more than 10-15% at the pump intake, we would become more concerned with the need for gas separation.

VFD or Variable Drives:
For critical installations, many times the data is such that the design may not fit the well conditions as the operator would prefer. Also changing well conditions may require changes in the ESP operation before the unit is pulled. If sufficient motor capacity is available, then a VSD can help achieve optimum operating conditions before the unit is pulled.


Variable frequency drive (VFD) controllers are solid state electronic power conversion devices. AC input power is first converted to DC intermediate power using a diode rectifier and/or thyristor (SCR) bridge. The DC intermediate power is then converted to quasi-sinusoidal AC power using an inverter switching circuit. [1] Figure 1 is a basic block diagram of a VFD connected to a motor.



For the electrical submersible pump (ESP) application there is a step up transformer and a length of cable between the output of the VFD and the motor.

VFD's for ESP oil well applications are divided into two major categories. They are either variable voltage inverters (VVI) or constant voltage inverters (CVI).

AC motor characteristics require the applied voltage to be proportionally adjusted whenever the frequency is changed in order to deliver the rated torque. For example, if a motor is designed to operate at 460 volts at 60 Hz, the applied voltage must be reduced to 230 volts when the frequency is reduced to 30 Hz. Thus the ratio of volts per hertz must be regulated to a constant value (460/60 = 7.67 V/Hz in this case). For optimum performance, some further voltage adjustment may be necessary, but nominally constant volts per hertz is the general rule. This ratio can be changed in order to change the torque delivered by the motor. The VVI VFD controls the output voltage by controlling the DC voltage level with SCRs. The output of this type of drive is a quasi-sinusoidal wave called a 6 step shown below in Figure 2.



The vertical distance from the top of the top step to the bottom of the bottom step equals the DC bus voltage. As the frequency increases the SCRs on the input will cause the bus voltage increase and conversely when the frequency decreases the SCRs will reduce the bus voltage.

VVI VFDs with 6 step outputs have been applied to ESP oil well applications for over 30 years. There is some additional motor heating associated with the use of 6 step because on the harmonic content of the quasi-sinusoidal wave shape. This additional heating as been compensated for by using motors that have be re-rated for the application of 6-step VFDs.

The CVI VFD controls the output voltage and frequency with a pulse width modulated (PWM) output shown in figure 3 below.



The peak between the top of the positive pulses and the bottom of the negative pulses always stays the same (or constant voltage). The width (or duty cycle) of each individual pulse increases with increasing frequency therefore increasing the average applied voltage. This voltage and frequency control is shown in Figure 4 below. The average voltage over the low frequency period will be lower than the average voltage over the higher frequency period.



When the CVI VFDs are applied to the ESP oil well application, the rapid switching of the PWM output causes reflections to occur over the long lengths of power cable. This can cause voltage spikes up twice the peak system voltage to appear at the output of the step up transformer and the ESP motor terminals. Figure 5 shows the ringing that occurs at the end of the voltage transitions during the PWM switching.



To reduce the risk of insulation failure and to reduce motor heating due to harmonics the manufactures of these drives have included low pass filters on the output of their CVI VFDs. This is filtered PWM (FPWM3) or variable sine wave generation PWM (VSG PWM4). A typical voltage output waveform of a filtered CVI VSD is shown in figure 6 below.



Variable frequency drives for ESP oil well applications range in size from 25 KVA to 2000 KVA at 480 volts to 2400/4160 volts. They can be designed for stand alone applications in the field in NEMA 3 or 4 enclosures or they can be in NEMA 1 enclosures for motor control room applications. When purchased from an ESP vendor they will come with the necessary controls for motor and VFD protection and control.

1. Campbell, Sylvester J. (1987). Solid-State AC Motor Controls. New York: Marcel Dekker, Inc. pp. 79
2. Bose, Bimal K. (1980). Adjustable Speed AC Drive Systems. New York: IEEE Press
3. Registered trademark of baker-Hughes Centrilift
4. Registered trademark of Wood Group - ESP, Inc.

4) Installation:
a) There are many factors to be considered to prepare for installation, install the cable and unit components and start up and monitor the unit. See API RP 11 S3, Recommended Practice for ESP Installations. See API RP11S5 Recommended Practice for Application of ESP Cable. See APIRP 11S6 Recommended Practice for Testing ESP Cable Systems.

5) Operation / Monitoring:
i) Monitor: Amps, surface voltage, downhole temperature and pressure starts/stops, power supply frequency

ii) Advanced
(a) Motor winding and well temperature
(b) Motor fluid dielectric strength
(c) Vibration
(d) Discharge pressure
(e) See API RP 11S Operation, Maintenance & Toubleshooting of ESP Installations

6) Removal from Well/ Inspection;
i) Remove with care
ii) Inspect as removed: Sample fluids , solids etc
iii) Collect fluid and solids samples
iv) Observe color indicating exposure to excessive heat
v) Note Vibration marks if any
vi) Any evidence of cable or pothead burns
vii) Mechanical damage if evident
viii) Package including pothead and instrumentation (without removal) to shop for teardown

7) Shop Teardown:
i) Have available historical run data and documentation
ii) Sample internal materials and fluids
iii) Search for primary cause of failure and other conditions:
(a) Wear
(b) Foreign materials
(c) Electrical transients or electrical burns
(d) Water in motor?
(e) Seal function or failure of:
1. Shaft seals
2. Bag preventer
3. Contamination of labyrinth sections
4. Wear or failure of thrust bearing
(f) Motor: Burned or contaminated
(g) See API RP 11S Recommended Practice for ESP Teardown Report
iv) Determine possible reuse of pump and motor if reconditioned and tested. See APIRP11S2 Recommended Practice for ESP Testing. See API R P11S8 Recommended Practice on ESP Vibrations. See API RP 11S7 RP on Application and Testing of ESP Seal Chamber Sections

8) Determination of failure:
i) Examine removal and teardown data and assess cause/s of failure

9) Continuous Improvement:
i) Indicate equipment that could extend run life such as sand resistant
(1) Stages/ impellers or high temperature trim or need for better checks at installation etc. Note that these recommendations my not be implemented on the new equipment going in but possibly on the following run/pull/installation.

10) Maintenance of Failure Data Base:
a) In order to show improvements with time in run life, it is necessary to have a good record of past failures and the cause of each. Only then can attention be focused on the most critical areas and only then can improvements in run life be achieved.



For additional information on a failure tracking project details see: Industry
Reliability and Failure Tracking Joint Industry Projects seek to increase ESP and PCP Run-Life By Jesus Chacin, Paul Skoczylas and Darren Worth, Rogtec, Issue 7.

Labels: deployment, electric submersible pumps, ESP, factors for successful operation, oil gas, production, Russia, Zeitecs

posted by The Rogtec Team @ 11:48  0 Comments

TNK-BP strategy in exploration and production is focused on application of new technology to turn the Company's huge resources into proven reserves. TNK-BP's investment into seismic should be supported by solutions ensuring secure information storage, and investment into exploration should be supported by solutions ensuring data reliability and accessibility.



Oleg Bantyukov (ONBantyukov@tnk-bp.com), Data Quality Improvement Section Head, IT and Database Dept., TNNC


Pavel Potapov (PAPotapov@tnk-bp.com), Acting Head of Archive Systems Section, IT and Database Dept., TNNC

Data Management Organization of Tyumen Petroleum Research Center (TNNC) is in charge of developing a quality data management system in TNK-BP (see "Data Management: the Future is Defined by the Newly Established Organization", Innovator 20). Today, it manages all exploration and production data flows within the Company and supports all TNK-BP's Performance and Business Units. The Organization provides over 40 various services on corporate exploration and geological and geophysical (G&G) databases and archives to users from all subdivisions of the Company.

Creating TNK-BP Seismic Archive
One of the priority tasks for the TNNC data management specialists is to develop a corporate seismic archive.

The seismic data is currently stored in IT and Database Dept., TNNC, on a specially allocated 500 GB disc array, as well as in PCMS seismic data management system. However these recourses are not sufficient, and up to 75 percent of the information is stored on single-copy magnetic tapes. In standard conditions, these records loose their properties after five to seven years of storage. Thus, in several years the Company may loose up to 25 percent of the acquired seismic data if it does not provide the right storage conditions.

Moreover, data volume increase, random data storage on multiple media, data duplicating and lack of a consolidated corporate storage system hampers efficient work with the information and creates additional risk of data loss. These all dictated the necessity to develop a comprehensive shared information system to manage the seismic data and store primary seismic information and the results of its interpretation.

Over the last two years, TNNC has made major efforts to create and equip the Company's seismic archive which is to start working in 2009. In summer 2008, a core storage facility was commissioned; it is now being equipped - racks have been purchased to store the seismic data storage media (Fig. 1), their installation is planned for the next spring. Furthermore, terms of reference have been developed and approved to create an indexing system for the seismic data storage media. It is planned to begin its installation in December 2008. After that, the storage media will be marked and indexed. The system will provide for the opportunity to identify the location of the required data in 3D mode showing the numbers of the room and the shelf.



In January, a hardware and software complex will be shipped from Finland which will help expand the disc space for data storage and provide backup. In 2009, it is planned to equip the seismic data storage with a ventilation and humidification system to ensure reliable and longterm media storage, complete the data indexation, and arrange a centralized system for initial seismic data storage media search and complete the media bar-coding.

Data Quality Means Operations Quality
Another priority in data management is to ensure the quality of the G&G data. The lack of appropriate processes in the Company's PUs impacted data quality and integrity, as well as delayed its download into the Corporate Database (CDB). The inconsistence of information flows caused massive duplication both for the initial information and the interpretation results which resulted in the need for sidetracking and pilot drilling as well as causing unjustified expanses of the Company.



Data quality and integrity is negatively affected by the fact that PU specialists do not have a tool to check and visualize operational G&G data coming from the contractors. That is why the key objective for TNNC Data Management Organization in this field is to develop tools and software to control the quality and reliability of the information downloaded into the CDB. Data Quality Improvement Section within TNNC IT and Database Dept. is in charge of this work.

The Section initiated the development of software to convert unstructured G&G and exploration and production data into the Company's standard format and provided it to the contractors in geophysical studies. For the first time ever, the Company has developed regulations for the submitted data and the tools to convert the data into the desired format.

Thus, File Inkl View includes a standard algorithm to calculate directional survey parameters based on tool-measured parameters, such as depth, angle and azimuth; average angle method is used to calculate trajectory. VDL (variable density log) Converter is used to convert unstructured files containing cementing quality findings into structured WDEF files. Another tool, PGIS (Development Logging) Converter, converts unstructured files containing well log control findings into structured WDEF files. Templates for the created files are generated based on appropriate Corporate Technical Standards.

An effective tool was developed for PU specialists to evaluate input data quality based on certain criteria and visualize the acquired data in 3D mode.

File Inkl View is designed for directional survey data (Fig. 2). When analyzing the well data, the user can easily change the borehole image scale and dimensional orientation to view the trajectory from all sides. The software provides for batch control of structured files, and the quality of the provided geophysical data is assessed within minutes. FileTest is used to process structured text files containing well data in LAS (Log ASCII Standard) format, ver. 1.2, 2.0 and 3.0. PGIS Test checks the structured WDEF files containing well log data for certain types of errors, the list of which will be further expanded. Another tool, VDL Test, is used to menting quality findings. It helps identify gross errors in cement bond log findings at the initial stage, as well as submitting quality data to CDB.

All the software is conditioned for both individual and batch testing.

New Solutions to Ensure Data Quality and Integrity
To control the incoming file data integrity and track the information flow, TNNC specialists have developed ArchiveShare data flow management system. It includes of two subsystems.

The registering subsystem automatically receives the incoming data and includes it into own incoming database. The data sources may be an e-mail box, DVD, hard drives, or FTP. After this, the received data are located in dedicated file resources where they become available for further work.

The web-subsystem helps visualize these data. It has a set of functions to facilitate and manage data flow. Moreover, the web-subsystem uses e-mail to notify the users of key events, such as moving to the next stage of data processing or holdback.

To control data quality and integrity, CDB has tools for the comprehensive information assessment in data array. They help accumulate a studies knowledge hub which, in its turn, improves the data testing quality.

View Inkl is used to display and visually assess the quality of G&G information downloaded into BASPRO Database, including data on directional survey, segregations, layer intersection coordinates, wellhead coordinates, altitude, and correction of magnetic variation. The software enables us to track the path of an individual well or a whole well pad. Export Inkl is designed for modeling specialists. It helps obtain directional survey data for a PU from BASPRO Database. This can be done both in technical standard format (to submit data to regulators or contractors) and in a format ready to download into modeling software (subject to correction of magnetic variation).

In 2009 data management will become much more effective, upon implementation of technical standards and software for data quality control. The Company will be able to operatively track depletion of the remaining hydrocarbon reserves, simulate well interventions for enhanced oil recovery more accurately, and identify the most efficient and cost-effective options for reservoir development.

Labels: data management, Exploration, Information storage, production, Russia, seismic, TNK-BP, Tyumen

posted by The Rogtec Team @ 17:07  0 Comments

Jose Alvarez and Roy Coates
Alberta Research Council

Canadian Heavy Oil Resources
The Western Canadian Sedimentary Basin (WCSB) contains as much as 30 billion barrels of heavy oil in place (OIP). Approximately two thirds of these resources, 19 billion barrels, are located in the heavy oil reservoirs of the Lloydminster area. Therefore, the Lloydminster area, located on the Alberta-Saskatchewan border, has a strategic importance for the energy sector in Canada as heavy oil production accounts for almost 20% of the total Canadian oil production.

The Lloydminster reservoirs are characterized by being very fine to fine grained relatively clean quartz unconsolidated sand bodies with porosities ranging from 29 to 35%. These relatively shallow reservoirs, 500 to 600 m deep, have temperatures around 22 0C and permeability values varying from 100 to 5,000 md. The oil gravity ranges from 13 to 17 0API and dead oil viscosities can be as high as 40,000 mPa.s. Additionally, around 80% of the OIP is found in formations that are less than 5 m thick, which leads to additional exploitation challenges.

Primary Production
Primary production, conventional or unconventional (cold heavy oil production with sand, CHOPS), in the Lloydminster area has been under way for about 60 years and is the technology applied by most of the Canadian heavy oil producers. Recovery factors are in the order of 8 to 15% OOIP. Cold Production takes the advantage of specialized pumping equipment, e.g. progressive cavity (PC) pumps, in order to deliberately produce sand along with the reservoir fluids. The production of sand creates long channels or wormholes with high permeability. Evidence suggests that some wormholes may grow as far as 200 m from the production well. The combination of foamy oil behavior and the high permeability channels accounts for the high recovery factors and high production rates encountered in most of the Lloydminster's reservoirs.

In spite of the commercial success of cold production, there are several indicators that suggest it may be reaching a plateau. Actual production is estimated to be 36,500 m3/d (230,000 bbl/d) and production forecasts are showing a 50% decline over the next decade. Several factors are contributing to this production decline:

• Industry is running out of new sites for cold production
• Watering out of wells due to water encroachment through wormhole systems
• Pressure depletion and reduced drive energy
• Low liquid inflow and high producing GOR
• Wells do not last more than 7 to 8 years due to above reasons

Therefore, the future of these reservoirs depends on the development of post-cold production technologies to tackle the remaining 85% to 90% of OOIP.



Post-Cold Production Technologies
Evaluation of follow up processes for mature cold production reservoirs has been a research topic for the last 15 years in Western Canada. Thermal and non thermal processes have been investigated at laboratory scale using reservoir properties representative of Lloydminster reservoirs. The aim of the research has been the development of an economically viable IOR process which utilizes the existing wells and wormhole networks to provide access for injection of stimulation fluids into the formation. The injected fluids reenergize the formation, supply drive energy and correct mobility imbalances through viscosity reduction and phase redistribution.

The experiments are performed in a radial drainage apparatus, representing a segment of the reservoir draining into a 6 cm diameter wormhole located in the middle of 6 m thick pay zone. The assumption for this configuration is that once the wormhole is created, the mechanisms controlling fluid production generally affect the flow of fluids between the reservoir and the wormhole, and that this flow is in a radial direction. The model is 3 m in length, with a 1 cm internal diameter at the bottom and a 12 cm internal diameter at the top.



More than 15 experiments were performed in the radial drainage apparatus evaluating thermal and non-thermal follow-up processes.



Thermal Processes
Economical analysis, based on simulation results, indicated that cyclic steam stimulation (CSS) has more potential to be economic in thicker reservoirs, i.e. pay zones greater than 15 m. This observation is in line with that reported from field experiences in thin pay zones of Lloydminster, where high heat losses have produced uneconomic outcomes. These results rule out thermal processes for more than 80% of the Lloydminster reservoirs.



Non-Thermal Processes
In the cyclic solvent injection concept (CSI), a solvent mixture is injected in the reservoir, followed by a soak period and a production period, analogous to the CSS process. As a rule of thumb, the solvent mixtures to be used in the CSI process should be predominantly gaseous to replace the voidage created by primary production, have good solubility in oil, be readily available and be relatively inexpensive. With those requirements in mind several solvent mixtures have been evaluated. These mixtures consist of an inexpensive carrier gas such as methane or carbon dioxide, enriched by propane or butane. The mixtures compositions were selected such that for the experimental pressure range, they were either in the gas phase region, close to the dew point or in the two phase region. Operational conditions, such as number of cycles, soak time, solvent loading, comingled or slug injection strategies, are key in this process and should be evaluated in physical and numerical models before testing the CSI technology in the field.

The figure shown below compares the recovery factor between methane based mixtures and carbon dioxide based mixtures with propane. Carbon dioxide based mixtures have two to three times higher recovery factors than the ones obtained by methane based mixtures. Higher oil swelling, higher dissolution and greater viscosity reduction with carbon dioxide can be responsible for the higher oil recovery. Additionally, associated experiments carried out to examine exsolution behavior of different solvents from heavy oil, have reported abnormally high supersaturation of carbon dioxide. This behavior may be the key to the additional recovery obtained with carbon dioxide mixtures. Further investigations are ongoing.



CSI Pilot Tests
Husky Inc. is operating the Edam field in the Lloydminster area. A blend of methane-propane began to be injected in June 2006. Injection and production were cycled between two unconsolidated-sands formations. One of the formations is 7 m thick, containing 12 0API oil with a viscosity of 15,000 mPa.s. The other formation is thinner, 3.5 m of pay, containing a more viscous oil, 27,000 mPa.s and 110API. The thicker formation had average oil recovery during cold production but little water production. The other formation produced above average water and oil during the cold production. The reported information for this pilot indicates that the results have been encouraging and therefore the operator will continue evaluating CSI operational strategies in this field.

For More Information, Contact

Jose Alvarez, Ph.D
Solvent Strategic Area Leader,
Heavy Oil & Oil Sands,
Alberta Research Council,
Edmonton, Alberta, Canada,
T6N 1E4
Phone (780) 450-5395

Roy Coates, P. Eng
Reservoir Engineer Manager,
Heavy Oil & Oil Sands,
Alberta Research Council,
Edmonton, Alberta, Canada,
T6N 1E4
Phone (780) 450-5261

Labels: Alberta research council, Canada, CSI, Cyclical Solvent Inject, Heavy Oil Recovery, production, steam

posted by The Rogtec Team @ 16:22  1 Comments