Steam Assisted Gravity Drainage With Electric Submersible_4072657_01

7/21/2019 Steam Assisted Gravity Drainage With Electric Submersible_4072657_01

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This paper was prepared for presentation at the 2005 Society of Petroleum Engineers - Gulf Coast Section Electric Submersible Pump Workshop held in Houston, Texas 27-29 April2005.

This paper was selected for presentation by the ESP Workshop Panels (Rotating and Permanent) following review of information contained in an abstract submitted by the author(s).

Contents of the paper, as presented, have not been reviewed by the ESP Workshop Panels and are su bject to correction by the author(s). The material, as presented, does notnecessarily reflect any position of the ESP Workshop or its panel members. The author(s) retain copyright to this paper and have given permission to the ESP Workshop to publish it in

proceedings (electronic and hardcopy). Any other electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the

author(s) is prohibited.

Abstract

With much of North America’s reserves of light oil having passed their peak levels of production, attention is now being

focused on cost effective methods to produce heavy oil or bitumen. Steam Assisted Gravity Drainage (SAGD) has proven to be a successful method to develop EnCana’s bitumen and heavy oil reservoirs in Canada; at Foster Creek,

Christina Lake, and Senlac. Key to the economic success of this method is the ability to operate the process at anarbitrary pressure suited to optimize: 1) steam oil ratio (SOR) and 2) production rat es. Generally, this entails operating at

pressures lower than those normally needed for Gas or Steam Lift, the method of choice before 2001. At lower

pressures, the production rates required to make SAGD economically viable are well suited to the use of electric

submersible pumping systems (ESP’s). ESP’s, however, have been typically limited to well temperatures below 180 °C(356 °F) and were not compatible with the higher well temperatures required with SAGD to optimize production. This

paper describes the successful use of ESP’s in conjunction with SAGD for producing heavy oil based on the development

of a fit-for-purpose ESP system with specially designed pumps, protectors, motors and cables for service at temperaturesup to 218 °C (456 °F). Advancements in ESP technology for SAGD operations were proven in the laboratory through

extensive environmental and performance testing and validated through field-testing. This fit-for-purpose ESP systemhas been installed in over 14 wells and has achieved run times of over a year with production rates of approximately

7,000 m³/d (44,000 bfpd). Details of the ESP system, qualification testing and field implementation are presented.

SAGD TechnologySteam Assisted Gravity Drainage process is a conceptually simple technology but complex in application. The process,

illustrated in Figure 1, utilizes two parallel horizontal wells roughly 750 meters (2450 feet) long horizontally, drilled parallel in 15 to 35 meters (50- 115 feet) of pay. The lower well is used as the producer, while the top well, located 5 m

(16 ft) above, is the steam injection well. The SAGD process involves dry steam injection steam into the oil sands,

creating a high-temperature steam chamber in the formation. As steam is introduced, it flows through the sand to theinterface with cold oil where it condenses. The resulting heat transfer lowers the viscosity of the oil near the interface

and allows it to drain by gravity to the horizontal production well below. The resulting emulsion in the producing well, ~

70% water, is lifted to surface. A reference list is provided at the end for addition reading on SAGD.

Steam

Emulsion

Figure 1.0 Steam Assisted Gravity Drainage.

Steam Assisted Gravity Drainage with Electric Submersible Pumping Systems

Sandeep Solanki & Brad Karpuk – EnCana Oil & Gas Partnership, Calgary, Alberta Canada

Robert Bowman – Schlumberger Canada Ltd., Calgary, Alberta CanadaDavid Rowatt - Schlumberger Bartlesville Product Center, Bartlesville, OK USA



2005 ESP Workshop Steam Assisted Gravity Drainage with Electric Submersible Pumping Systems 2

Artificial Lift is necessary to raise production fluids to surface, due to the depth of the reservoir and the SAGD operating

pressure. To date, due to the higher operating pressures and temperatures (> 220°C(428 °F)) most applications use a‘poor boy’ Gas Lift system. This was based on injecting gas (generally methane) down the annular space between the

casing and production tubing, without the provision for any gas lift valves.

Low Pressure SAGD

In many areas where heavy oil bitumen is located, there exists a gas cap over the bitumen, which has been produced by a

number of operators. In order to use SAGD to recover bitumen in these areas, there must be a balance between the gascap pressure and the SAGD chamber operating pressure. This can be achieved either by repressuring the gas cap or

operating the SAGD chambers at lower pressure. Figure 2.0 below shows the typical geological depositionalenvironment illustrating the top gas and bottom water zones that, in turn, dictate the pressures we are restricted tooperate SAGD at.

Figure 2.0 Geological Model for Various Bitumen Depositions.

Operating the SAGD chamber at lower pressure can also improve economics. Steam accounts for 35-55% of the total

extraction cost and is proportional to the operating Steam Oil Ratio (SOR). Numerous publications have clearly shown

that operating at lower pressures can significantly lower the cumulative SOR and optimize the economics of SAGDoperations.

As the operating pressure is lowered Gas Lift becomes inefficient and can lead to unstable operations or in many casesnot at all viable to achieve desired production rates. Pumps are the only alternative to operate the process at low pressure

given such circumstances. Lower pressure operation using pumps can also result in other advantages such as:

• Smaller pad facilities , by eliminating the need for separators and seperate transport of gas and emulsion to the

plant.

• Fewer smaller pipelines to transport the fluids to the plant, since pumps allow for direct transport of emulsion to

the plant. This becomes more important as the pads become located further away from the plant.• Full independent control of the chamber, no dependence of fluid rate on chamber pressure.

• Smaller plant facilities due to smaller volumes of gas being handled.

Recognizing the benefits of pumps, EnCana has been leading numerous initiatives to develop alternative lift systems forSAGD. The benefits can only be capitalized on if an economic pumping system is developed. Key to the use of pumps

is to ensure that sufficient run life is achieved so as not t o wipe away the benefits realized. EnCana feels that a minimum

Mean Time To Failure (MTTF) of 1 year is needed to achieve this and to provide sufficient benefit for the use of pumps.One successful development has been a fit-for-purpose ESP system from Schlumberger specific to SAGD operations.

Foster

Creek Christina Lake

Regional O/W

Contact

SAGDInterval

SAGD

Interval




The scoping exercise was successful in focusing engineering resources for all major components. The overlying principle used for engineering the system was that the maximum operating temperature of each component must not be

exceeded. The operating temperature is not to be confused with the fluid temperature. The operating temperature is

defined as the internal temperature of the component, which is generally higher than the produced fluid. Thistemperature increase is due to mechanical and electrical losses in the system.

Pump

As a purely mechanical device, pump development was minimal. Key areas of concern were thermal growthconsistencies between shaft and stage materials as well as o-ring temperature limits. The scoping exercise determined

that the fluid temperature within the pump must be kept below 288 °C (550 ºF) to maintain the o-ring integrity based on perfluorolastomer temperature limits. Calculation of fluid temperature in the pump must include the heating caused bythe motor, protector and the stages in the pump with the maximum temperature calculated at the top of the pump. The

maximum pump length for any section is limited to a continuous section to better define thermal growth. Shaft

horsepower is derated at temperatures exceeding 20 4 °C (400 °F).

Intakes/Gas Separators

Similar to the pump, the engineering review was limited to o-ring applicability and thermal growth considerations. All

conventional intake types can be used in the defined SAGD application conditions. Selection of the type is determined by

expected fluid properties (i.e., gas/steam presence requiring separation or selective production from the bottom of thehorizontal wellbore).

ProtectorEngineering resources were particularly focused on the protector, as it is the critical component in protecting theelectrical integrity of the motor. Conventional systems were discounted due to SAGD operational requirements.

Labyrinth style protectors that use a tortuous path to limit wellbore fluid entry into the motor are not applicable in

systems with horizontal orientation. Positive seal elastomer bags do not have sufficient tensile strength or maximum

operating temperature limits high enough to meet the maximum operating temperatures and thermal cycles requirementsassociated with SAGD operations.

To circumvent these limitations, many different protector designs were considered that employed one or more of thefollowing well fluid barriers: metal bellows, pistons, powered bellows and pistons, surface oil injection, magneticcouplings, 3-D labyrinth chambers and heavy barrier fluids. Due to cost and time considerations, a positive pressure

bellows protector was proposed. It incorporates a patented metal bellows design instead of bags or labyrinths to allow

for pressure equalization and oil expansion. A depiction of the metal bellows design versus conventional protector

designs is shown in Figure 4.0.

Figure 4.0 Protector Types

A high temperature perfluorolastomer compound rated for 288 °C (550 ºF) was used for the mechanical shaft seals and o-rings. Engineering design of the protector also included specification of a motor oil that would provide lubricity and

dielectric strength across the entire operating temperature range. This fluid was designed to maintain a viscosity above 2

cSt at 288 °C (550 ºF) (see Figure 5.0).




Figure 5.0 Protector/Motor Oil Temperature Profile

Finally, the protector development included an application program to model the expansion characteristics of the internal

oil and determine the number of bellows required for a specific application.

Motor

The application engineering design goal for the motor was to keep the internal motor winding temperature below 288 °C

(550 ºF). Design of an application engineering program incorporating the fluid properties and flow rate past the motor

was completed to ensure that the maximum internal temperature is not exceeded during operation.

The motor was based on the existing 562 series Dominator design. This design incorporates an all -steel stator with

locked rotor bearings, an outboard abrasion resistant rotor bearing in the base, an oil filter, and high load thrust bearing.

Other modifications include high temperature o-rings rated for 288 °C (550 ºF) and high temperature slot liner material.The head has been modified at the pothead hole to accept the high temperature pothead design.

The maximum horsepower rating for the motor is 21.4 hp/rotor. Motors can be de-rated from this value to match surface

voltage supply, pump requirements and/or to decrease the internal operating temperature further. The maximum

temperature cycle and the number of bellows available in the protector also limit the maximum horsepower rating of the

motor.

Pothead/Motor Lead Extension

A new pothead was designed for high temperature operations incorporating several new features in the potheadconstruction including a triple redundant sealing system utilizing high temperature solder, tubing crimps, and

perfluorolastomer o-rings. In addition, the snout seal is a new m etal spring energized seal. The pothead was designedfor a 260 °C (500 ºF) maximum, continuous operating temperature and is rated to 5kV. Since current heats up the

pothead in combination with the outside well temperature, the maximum current for both the pothead and the motor lead

extension (MLE) at various well temperatures was analyzed. Most calculations for maximum current are satisfactory justusing ambient fluid temperature; however additional motor heating can be a factor in some applications.

The MLE must withstand the temperature of the produced fluid, plus the temperature rise caused by the heat expended by

the equipment. The motor will cause heating of the fluid that surrounds the cable to the upper point of the intake. There

will also be migration of heat up the conductor from the motor connection. The protector will cause heating due to thedown thrust of the pump. The heat generated by the pump will also affect the MLE. It is to be assumed that pumpinefficiency is manifested in heat . The fluid in the pump will carry much of this heat away; however, some portion of the

heat will migrate through the housing and to the MLE. The cable used for the MLE is rated for 260 °C (500 ºF)

maximum operating temperature. The MLE was engineered with a dual, high temperature insulation system of polyamide and PEEK over each phase with an encapsulating lead jacket. It, like the pothead, is rated at 5kV.

The splice between the main cable and the MLE lead extension is rated at 232 °C (450 ºF). Sp ecial manufacturing

techniques and solder are used to make this splice withstand these higher service temperatures. As the cable and the

splice should not be subjected to temperatures above 232 °C (450 ºF), special care must be given to the application

engineering to ensure the MLE cable is used to a point above the ESP string where the temperature falls below thismaximum temperature.




Main Cable

Significant developments in the design of the main cable were not required. Existing EHLB (EPDM rubber compoundinsulation, heavy lead jacket, braid barrier) cable was specified as it has a maximum operating temperature of 232 °C

(450 ºF) and a voltage rating of 5kV. It must not extend past a point where the heated fluid in the production tubingexceeds the maximum temperature rating.

Pressure/Temperature Tool

Due to temperature limitations in existing conventional ESP monitoring tools, a complete redesign of the tools wouldhave been required to meet the application scope. As existing methods were in employ by EnCana (nitrogen bubble tube,

fibre-optic monitoring), development work in this area was not pursued.

System Testing and Qualification

Dynamometer testing in a temperature-controlled test well was conducted on the motor, pothead and protector to verifyoperation over the required temperature range. The rest of the components in the system did not undergo physical testing

at elevated temperatures. Engineering calculations and past history were used to assess the reliability of these

components under the stated operating conditions.

Environmental Qualification testing included:

1. Hot resistance testing to establish internal motor winding temperatures for motor rating guidelines.

2. 100-hour protector test at 100 HP, BHT of 235 °C (455 °F).

3. Operational t hermal cycle testing of the motor and protector at 100 HP over a 235 °C (455 °F) to 188 °C (370

°F) to 235 °C (455 °F) BHT temperature range.4. Pressure testing of the motor and protector at a BHT increase of 83 °C/hr (150 °F/hr) (no pothead installed,

pothead shipping cap used to seal motor pothead opening).5. Operational thermal cycle testing at 150 HP over a 218 °C (425 °F) to 79 °C (175 °F) to 218 °C (425 °F) BHT

temperature range vented to prevent a vacuum on the motor.

6. 100-hour guarantee test at 150 HP, 218 °C (425 °F) BHT.7. 100-hour qualification test at 260 °C (500 °F) BHT and 100 HP (42 °C (75

oF) above required guarantee BHT

and at 288 °C (550 °F) winding temperature).

The results of the environmental qualification testing satisfied the criteria for promotion to field trial.

Field Trials

Figure 6.0 below shows the locations of EnCana’s three producing operation in Canada, Foster Creek, Christina Lake andSenlac, which use SAGD technology to recover 10.5 to 13 ° API bitumen and heavy oil from unconsolidated sands.

Calgary Calgary

Edmonton Edmonton

Red Deer Red Deer Senlac Senlac

Foster Creek Foster Creek Chr ist ina Lake Chr ist ina Lake

38 Well Pairs 38 Well Pairs



Christina Lake Christina Lake

Figure 6.0 Location of EnCana's SAGD Operations in Canada.




The Foster Creek project, Canada's first large -scale commercial SAGD project, is producing over 30,000 bopd and

continues to expand. EnCana's thermal oil recovery project at Christina Lake in northeast Alberta is producing about5,000 bopd. The Senlac project in Saskatchewan is also producing about 4,000 barrels per day.

Typical operating conditions for the wells include:

• Bottom pressures of 2000 – 3000 kPa (290 – 435 psi);

• Bottomhole producing temperature: 180-209 °C (356 – 408 °F);

• Fluid rates of 500 – 1000 m³/d (3150-6300 bfpd);

• Water cut of 50 -90%;• Free gas at pump intake : 0 – 50%;

• Wellhead temperature of 175-190 °C (347 – 375 °F); and

• System power 65 – 250 hp.

Until 2001, all well pairs at Foster Creek were produced using gas lift. In 2002, EnCana field trialed the Schlumberger

Hotline ESP, rated to only 180 °C in AP3. That unit ran for 645 days and based on its success and the development ofthe SAGD ESP's, EnCana undertook the risk to field trial the first unit in BP9. Figure 7.0 shows the 309 day

performance of this first unit. Operation data collected during the field trial included producing pressure, via gas

bubbling system in a 48 mm (1.9 inches) side string, BHT via a downhole thermocouple in the side string and flow rateusing a surface flow meter. During the run the system was tested to operating Temperatures above 209 °C (408 °F)

showing that the system could be safely operated to this temperature. The ESP also underwent numerous shutdowns,

indicating the system could handle upsets and thermal cycling. Based on the success of this first unit, EnCana hascontinued to deploy more units as shown in Table 1.0. As of April 2005, there are 11 wells on pump at Foster Creek, 3

wells at Senlac and 1 at Christina Lake, have been converted from on Gas Lift to ESP, while 8 more wells (5 @ fosterand 3 at Senlac) have been started on ESP from day 1. Implementation of these units has allowed EnCana to build in-

house expertise and confidence in the systems to point where, all future pads at Foster Creek will be based on Pumps,taking advantage of optimizing pad facilities accordingly.

B H T

B H P

T o t a l F l o w R a t e

O i l R a t e

Figure 7.0 Field Performance of the 1st SAGD ESP at Foster Creek BP9.

EnCan a has continued to utilize SAGD ESP's, expanding their use in Senlac to take full advantage of Lower Pressure

SAGD. Senlac is a deeper formation located at 780 m, where the SAGD operating pressures have been lowered from

4,000 to 2700 kPa, resulting in lowering the SOR from 2.8 to below 2.0. This has transformed this small 'pilot' project

into positive money making commercial project, with plans to develop continuing phases to maintain production well

into 2012.

Recently, EnCana continued the field trials, and has begun to field trial ESP's at Christina Lake as well, to further

evaluate their performance at our other operations.

Steam Assisted Gravity Drainage With Electric Submersible_4072657_01

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