ENHANCED OIL RECOVERY OF SHALLOW WELLS WITH HEAVY OIL: A CASE STUDY IN ELECTRO THERMAL HEATING OF CALIFORNIA OIL

WELLS

Copyright Material IEEE Paper No. PCIC-2009-33

Greg McQueen, PE, PMP David Parman, P.Eng. Heath Williams Tyco Thermal Controls Tyco Thermal Controls E&B Natural Resources 7433 Harwin Drive 7433 Harwin Drive 1600 Norris Road Houston, TX 77036 Houston, TX 77036 Bakersfield, CA 93380 USA USA USA gmcqueen@tycothermal.com dparman@tycothermal.com hwilliams@ebresources.com

Abstract – A combination of uncertain oil prices and the shortage of easy to produce oil has led energy companies to look to develop difficult oilfields that in the past would have been considered uneconomic. Even abandoned fields are being reopened with less than ideal recovery methods. It is with this mindset that many energy companies are looking to utilize new technologies or new technology applications to maximize the production of heavy oil wells where production has either decreased dramatically over the years, resulting in fields that – while still having ample reserves – are not considered to be viably economic to produce, or have not been economically viable given heavy oil production costs. Specifically, in California, approximately half of the state’s crude oil reserves consist of heavy oil. However, using current or dated technology, less than nine billion barrels of heavy oil have been produced from an original total resource of 77 billion barrels. [3] This paper explores the utilization of Electric Heat Tracing as a viable technology solution to bridge the gap between economic and uneconomic when considering heavy oil wells in the California region wherein production has dropped to an unacceptable level or production is not economically desirable. Historically, specific Electric Heat Tracing technologies have proven to be viable solutions – technically and economically – when considering the maximizing of well-output against the capital costs of new equipment required at the well. Recently, other Electric Heat Tracing technologies, such as Mineral Insulated Heating Cables or Skin-Effect Tracing Systems, have entered the arena of downhole heating or bottom hole heating considerations, providing a much needed solution for the development of the more difficult reservoir conditions. With this mindset, this paper will look at the specific application needs (i.e. heavy oil reservoirs throughout the California region), the available technology solutions with specific emphasis on Electric Heat Tracing, and the expected and realized results through the use of these available technology solutions. Further, this paper will highlight the system requirements for this solution, and the associated cost; with specific emphasis on return on investment when considering capital cost and operating cost expenditures. Index Terms – Electric Heat Tracing, Down Hole Heating, Bottom Hole Heating, Heavy Oil, Enhanced Oil Recovery, Controls, Power Distribution, Oil Production.

I. INTRODUCTION

Unconventional oil has many definitions within the oil industry, and often includes the broad term heavy oil. In simplest terms, crude oil is a mixture of hydrocarbons such as paraffin, aromatics, napthenes, resins and asphaltenes. The heavier crude has proven to be problematic over the years due to the highly viscous nature of heavy oil and the inherent difficulties of producing these reservoirs at a production-rate that is economical. Oil is considered heavy if it has 10-20 API gravity, or viscosity from 100-10,000 centipoise at original reservoir temperature. Heavy oil in California is approximately 13-API gravity, or close to 5,000 centipoise. [3] One of the largest fields of heavy oil in the United States is located in Kern County, California, approximately 160 kilometers north of Los Angeles.

The Kern County reservoirs are estimated to be a 40-billion-barrel resource, primarily of heavy crude located in shallow reservoirs. Production of these heavy oil reservoirs was slow until the introduction of steam in the 1960s to reduce the viscosity. Through the cyclic steam process and steam floods, producers were able to reach a peak production in the mid-1980s of 250-million-barrels/year. Environmental concerns contributed to increasing costs of production, and since then – with as much as 65% of the original oil believed to still be in place – production has dropped off considerably. [3]

Today, with over 70% of the production in Kern County being conducted by independents and the economics and environmental concerns taking on a heightened presence in production, alternative methods of oil recovery are being considered. Hence, the consideration of Electric Heat Tracing as a viable solution for the enhanced oil recovery of shallow low-flow wells in the Kern County region.

For the purposes of this paper, the application being presented involves an onshore well currently in development outside of Bakersfield, California, in the Kern County region. The specific field being developed has a reservoir temperature of 120°F (49°C); the reservoir depth is approximately 1400ft (427m) with an expected total production rate of 10-20 barrels per day. The combination of these and other factors posed several challenges relative to technology selection and physical deployment, all of which are presented further in the body of this paper.

A. Traditional Methods of Enhanced Oil Recovery of Shallow Low-Flow Wells

Crude oil development and production in the United States

has three distinct phases: primary, secondary and tertiary recovery. Primary recovery involves the natural pressure of the reservoir along with artificial lift methods to produce oil reserves to surface. Under primary recovery, depending on the nature of the reservoir and oil characteristics, normally only 10 to 25 percent of the oil is recovered economically. Secondary recovery involves injecting either gas into a gas cap or water into the waterleg of a reservoir to regain pressure and energy to allow oil to flow to the wellbores. This process normally produces 20 to 40 percent of the original oil in place. Tertiary processes have been developed and several methods have been utilized in an attempt to prevent or at least mitigate the impact of the viscous nature of these heavy oils. These include such methods as Thermal Recovery Process, which consists of cyclic steaming, steam flooding and in-situ combustion; Chemical Flooding, which includes polymer and surfactant flooding; and now more recently CO2 flooding is beginning to take precedence due to new environmental laws and carbon sequestration. These processes have been developed because in many reservoirs the oil viscosity is so high that primary recovery is not sufficient to adequately produce the oil in place. A brief look at these methods highlights some of the drawbacks inherent in each.

Kern County has more thermal recovery projects than anywhere else in the United States. Fields like Kern River, Belridge and Midway Sunset are a few of the large fields where the steam flooding and cyclic steaming processes are taking place. The companies responsible for developing these heavy oil reserves have invested greatly in the infrastructure required to steam high viscosity oil reserves. Steam generators, cogeneration facilities, dense well spacing, high volumes of natural gas and fresh water are required to make these projects viable. The principle concern is that these projects are highly capital-cost intensive and would be uneconomic on a smaller scale. That is where the downhole heaters come into play. The downhole heaters can be economically deployed in a well by well case where large infrastructure and capital projects can not be economically justified.

Along with the steam processes, in-situ combustion, polymer and surfactant flooding have been deployed in heavy oil fields. In-situ combustion is a process where air/oxygen is injected into the reservoir. At pressure, oil around the injection well ignites and produces heat. The heat reduces the viscosity of the oil allowing it to flow and be produced in the surrounding wells. This is a destructive process due to well failures, and oil reserves are lost. This technique has been tried but has almost always been an economic failure. Surfactant flooding involves injecting a surfactant with injected water. This is similar to a waterflood but where the chemical injected reduces the oil viscosity and allows reserves to flow. Due to the high cost of chemicals, economic success is limited. Polymer flooding is a similar approach to surfactant flooding but instead of reducing the viscosity of the oil it increased the viscosity of the water so that viscous fingering does not occur. This method also only has minimal results. These three methods have not been proven to be

economically viable in any large scale heavy oil recovery projects.

Recently, since about 1972, in Scurry County Texas with federal and state legislation being passed for oil companies to be more environmentally friendly, CO2 flooding and sequestering has gained the spotlight. This process involves capturing CO2 emissions from an industrial facility or CO2 gas field and injecting the waste gas into heavy oil reservoir. CO2 mixes with the heavy oil and reduces its viscosity. The produced oil is then stripped of its CO2 and sold. The produced CO2 is then reinjected. This process is capital-cost intensive due to the specialized corrosion resistant facilities required to collect, inject and remediation of the recycled gas. The main reason that this has been economically successful in places like Texas is due to federal and state subsidies.

B. Utilization of Electric Heat Tracing

Electric Heat Tracing has been used in the past – for at least 20 years – as a viable solution for freeze protection, process temperature maintenance and heat-up of specific processes. For down hole heating (DHH) services, one of the early successful application utilized Self-Regulating (SR) Electric Heat Tracing technology, which eventually transitioned to the use of polymer insulated Constant Wattage (CW) Electric Heat Tracing technology. This technology provided an effective solution for wells with heavy crude as well as low-temperature wax, paraffin and hydrate issues, but is eventually limited by the amount of thermal power density the CW electric heat tracing cable is able to produce. Within the past few years, the viability of Mineral Insulated (MI) Electric Heat Tracing, another type of Constant Wattage cable, as an effective Down Hole Heating solution has been explored and implemented. Table I shows the basic technical specifications of each of the two principal Electric Heat Tracing technologies discussed above.

TABLE I

ELECTRIC HEAT TRACING TECHNOLOGIES

Constant-Wattage (polymer insulated)

Mineral Insulated

Maintain Temperature Up to 122°F (50°C) Up to 1022°F (550°C)

Maximum Heat Output 12.5 W/ft (41 W/m) 82 W/ft (269 W/m)

Maximum Heater Length Up to 3608 ft (1100m) Up to 5740 ft

(1750m)

Each of the above technologies was considered for the application discussed in this paper, and each is explored in more detail further on in the body of this paper so as to present a more comprehensive case for the importance of technology selection relative to this application.

A typical system is depicted in Fig 1. In this system, as a minimum, the scope would include the electric heater, a thermocouple for down hole temperature indication, a means to affix the heater to the production tube, a wellhead penetration for the heater to be brought to topside, and a control/power panel and transformer. In this case, the heater is applied to the outside of the production tube.

Figure 1 Typical System

II. BODY A. The Challenge

The targeted well for this consideration was located in Kern County, California. The reservoir contained heavy oil with a 14.3 API viscosity at 60°F (15.6°C). The primary specifics of this well are as shown in Table II with a schematic of the well in Appendix 1.

TABLE II

BASIC CHARACTERISTICS OF THE SUBJECT WELL Characteristic Value

Reservoir Depth 1499 ft (457 m) Reservoir Temperature 120°F (49°C) Casing Diameter 7 in. Total Liquids Production Rate 6 BLPD Production Tube Size 2-7/8 in. Viscosity, API Gravity 14.3 @ 60F Viscosity, centistokes 365.8 @ 120F Viscosity, centistokes 92.3 @ 160F Viscosity, centistokes 33.6 @ 200F

In order to achieve an increased production rate on this well, a specific amount of heat would need to be introduced to the wellbore in the reservoir area. By adding heat to this section of the production tube, it was expected that the increased temperature would expand into the reservoir. By extending the heat out away from the production tube and into the reservoir, we would be heating the heavy oil above its reservoir temperature and decreasing its viscosity, thereby allowing for better flow up to and in to the production tube itself.

Fig. 3 Typical Application There were several challenges inherent with this solution.

To increase the production flow, a relative large amount of heat would need to be input into the immediate area of the reservoir; so, in effect, the heat itself would need to be concentrated towards a relatively small area of the total production tube length. This is the payzone area of the reservoir. Similarly, since this is a relatively small diameter production tube, the heat tracing itself would need to either be able to input a large amount of heat through minimum passes; or be of a small enough diameter so that multiple passes could be installed. And, finally, the technology would need to be rugged enough to withstand on the tubing and long term wellbore conditions. All of these factors, and many more, played into the overall technology selection as solutions were sought for this application.

B. Possible Electric Heat Tracing Solutions

Electric Heat Tracing (EHT), as an industrial technology, is governed by IEEE-515 [1]. The most common form of electrical heating is the production of heat in an electrically conductive or semi-conductive material occasioned by passing an electric current through the material.

EHT has been considered an effective solution for flow-assurance, wax, paraffin and hydrate concerns for over two decades, with the primary technical solution being an armored polymer-insulated Constant Wattage (CW) technology. The previous CW heating cable technology historically used consisted of three insulated conductors running parallel to each other. The conductors are insulated and have a metal braid, polymer-jacket and overall armor. A voltage is applied across the conductors, causing current to flow, generating heat. The three-phase CW heating cable, as shown in Fig 4, is an industry-proven solution with literally hundreds of Down Hole Heater installations worldwide. For this application, though, the CW technology would not be able to produce the amount of heat-output required for this unconventional reservoir given the number of passes that would be required. Further, space limitations were also a consideration, as the CW cable would require multiple passes to produce the amount of heat necessary for this application, and the cable itself when applied to the small production tube would have made the application difficult if not completely impractical.

Fig. 4 Polymer Insulated Constant Wattage Cable Mineral Insulated (MI) EHT, as shown in Figure 5, was

considered next. This cable consists of one or two conductors embedded in a magnesium oxide insulation enclosed in a metal sheath. The series-type MI heating cable has been utilized successfully for conventional applications – topside pipe and equipment – for decades, but it has only recently been utilized in the oil-production industry as a viable solution for down hole heater applications, specifically for low-flow, shallow, aging wells, monitoring application for cyclic steam stimulation applications and specific flow-assurance (i.e. wax/paraffin issues) applications. For this application the MI technology proved to be an ideal solution given its rugged construction, high heat output capability and relatively small diameter when compared to the CW cable.

Fig. 5 Mineral Insulated Cable For this specific application, it was decided to utilize a

single-circuit MI cable with characteristics as described in Table III. In total, the design accounted for six passes of single-circuit MI cable with a heat output of 25.7 kW over the 90’ reservoir area. Revisiting each of the aforementioned concerns, the cable itself was designed to produce up to 48 watts/foot (157 watts/meter); was fabricated to a smaller heater diameter of 0.184”; and, as is typical for this technology, was also fabricated with a rugged Alloy 825 sheath for additional protection during installation and operation. The specifics of this heat trace cable are provided below in Table III.

TABLE III

CHARACTERISTICS OF THE MI CABLE TECHNOLOGY Characteristic Value

Cold Lead Length 1400 ft (427 m) Heating Cable Length 536 ft (163 m) Heated Section Passes 6 Heated Cable Diameter 0.184 in. Total Power Output 25.7 kW Power Output per foot of Wellbore 286 W Voltage 600 V Phase 1 Inrush Current (at 20C) 69 amps

The above heater was designed and fabricated with a continuous heated section and no hot-to-hot splices. The 1400ft (427m) length of cold lead required four cold-to-cold splices. The only other splices required for this application were at the hot-to-cold connections. Ensuring that there were no hot-to-hot splices was important as space limitations were of enormous concern, and providing as much space as possible for actual heater was important for the desired results. A sketch of this type of cable is shown below as Fig. 6.

Fig. 6 MI Cable Configuration

C. Control & Monitoring Solution

A diagram is presented in Appendix 2 that illustrates the control and monitoring configuration used for this solution. The control concept for this system was simplicity. A temperature indicator was incorporated into the panel with a direct connection to a Type-K thermocouple; the thermocouple sensor was installed in the well just above the payzone so that the most accurate readings could be taken. Other than the temperature indicator, readings such as current, voltage and ground fault sensors were incorporated. The system is intended to be either on for production, or off for shut-in. The amount of heat being put into the reservoir will be constant throughout, providing maximum reduction of the oil viscosity in the near wellbore reservoir area. D. System Performance and Results

The results from this application solution to a bottom hole heating need surpassed the original expectations from a technical and economic perspective. With the incorporation of the above technology, the production of this well was increased substantially. Table IV below provides a comparison of the well’s production rates before and after installation of the heater. Note that the Production Flow Rate prior to implementation of the bottom hole heating system was dependent upon ambient conditions. In other words, on cold days the well would be left idle, as the derived benefits from production did not outweigh the operation costs, and on hot days the well would produce up to 6 BLPD.

TABLE IV

SYSTEM PERFORMANCE AND RESULTS Before After

Bottom Hole Temperature 120°F (49°C) 240°F (116°C) Production Flow Rate 6 18

As the results above indicate, the production flow rate literally tripled, and the bottom hole temperature – critical for increased production – increased dramatically.

From an economic perspective, the following data, shown on Table V, was used to arrive at a total cost of ownership. This data is based on early 2009 information, as it is recognized that cost data of this nature is, especially as of late, in constant flux. At the time the system was actually

installed, the price per barrel of oil was in the $90 range, so the return on investment would have been a considerably shorter duration of time.

TABLE V ECONOMIC ANALYSIS CRITERIA

Criteria Cost BasisElectricity Cost $0.09/kWH Heater Output 25.7 kW Price of Barrel of Oil (NYMEX) $40.00 Heavy Oil Discount Factor 85% Heater/System Cost $60,000 Install Cost $20,000 Site Electrical Cost $10,000

From the economic criteria above, an overall payback period calculation was developed. First, we looked at the overall revenue Increase from the technology application:

(18 BLPD – 6 BLPD) x $40/B x 0.85 = $408.00/day

In order to arrive at an investment payback number, the

operating cost Increase to produce the additional 12 BLPD is calculated as:

25.7 kW x $0.09/kW-hr x 24 hrs = $55.51/day So, from these two values we are able to calculate the net

daily revenue increase: $408.00 - $55.51 = $352.49 The simple payback period is then calculated as total cost

of installation divided by the revenue increase: $90,000 / $352.49 = 255 days (8.5 months) This is an impressive result by most business standards

even at a moderate oil price.

III. CONCLUSION

In order to effectively develop resources from unconventional reservoirs, specifically where low-flow conditions exist due to heavy oil characteristics, unconventional solutions should be sought. While polymer insulated Constant Wattage Electric Heat Tracing has been used successfully in the past as a Down Hole Heating solution, its widespread use has been limited due to lower heat output.

With the recent successes of the Mineral Insulated Electric Heat Tracing technology applied towards Down Hole Heating, the solution potential for these difficult to produce reserves suddenly becomes not only viable, but attractive from an economic standpoint.

With MI manufacturing capabilities continuing to produce more robust cables, resulting in higher quality and longer heat trace cables/systems with high heat output, the spectrum for solution-oriented options increases. Following on this, through the use of this EHT technology, a degree of control

could be achieved that is not available with typical conventional solutions such as steam or chemical injection.

Fig. 7 Picture of Installation As can be seen from the results of applying this technology

to the low-flow shallow well applications, there now exists a viable enhanced oil recovery solution to these localized wells, many of which have lain dormant for decades. Through the use of unique Electric Heat Tracing technologies and, more specifically, the Mineral Insulated technology, previously unattainable production can be achieved with minimum capital investment and with a desirable return on investment for operators.

IV. ACKNOWLEDGEMENTS The authors would like to thank the following people for their assistance during the writing of this paper: Jim Summers for his insight into the low-flow shallow well landscape and his assistance in mining for data that was relevant and key in developing this paper; and Julie Ahner for her valuable assistance in proofreading various revisions of this paper and for supplying key points of data to help substantiate the overall findings.

V. REFERENCES [1] IEEE 515-1997, IEEE Standard for the Testing, Design,

Installation, and Maintenance of Electrical Resistance Heat Tracing for Industrial Applications, New York, NY: IEEE.

[2] C. James Erickson, Handbook of Electrical Heating for Industry, New York, NY: IEEE Press, 1995.

[3] Melanie Collison, California Heavy: Sharing Alberta’s Unconventional Oil Knowledge with the Golden State, Oilsandsreview.com

VI. VITA

Greg McQueen graduated from Texas A&M University in 1987 with a BS degree in mechanical engineering. He has held various roles within Tyco Thermal Controls, including Project Manager, Construction Manager and Business Development Manager, since 1998. He is currently Director of Technical

Services for the Strategic Business Unit. He is a registered Professional Engineer in Texas and Alberta; and received his Project Management Professional certification via the Project Management Institute. David Parman graduated from the University of Akron with a BS degree in electrical engineering, and holds an MBA in Global Management from the University of Phoenix. He is currently Director of Technology Development for Tyco Thermal Controls’ Strategic Business Unit, and is a registered Professional Engineer in Alberta. David is a member of the IEEE and ASME, and was a member of the IEEE 844 working group that developed the industry standards for skin effect systems. Heath Williams graduated from California Lutheran University with a BS degree in geology in 2004, and an ME degree in petroleum engineering from the Colorado School of Mines in 2006. He is currently the Production Engineer for E&B Natural Resources.

VII. APPENDIX

A1

A2