Application of Downhole Electric Heat Trace System in Arctic Completions

Fox, James B.; Earsley, Joseph D.

doi:10.2118/49188-ms

Cited by 4 publications

(3 citation statements)

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“…Currently, the average reservoir pressure is between 1400 and 1750 psi depending on the producing fault block. The geothermal gradient from surface to 2000 ft is 0.8" F/100 ft, due to the presence of a permafrost layer that extends to this depth (Fox & Earsley, 1998). From that point the geothermal gradient increases to 3" F/100 ft.…”

Section: Schrader Bluff Reservoir Fluid Propertiesmentioning

confidence: 97%

Supporting Technology for Enhanced Oil Recovery-EOR Thermal Processes Report IV-12

Izequeido¹

2001

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Section: Schrader Bluff Reservoir Fluid Propertiesmentioning

confidence: 97%

Supporting Technology for Enhanced Oil Recovery-EOR Thermal Processes Report IV-12

Izequeido¹

2001

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“…Electrical heating includes not only attaching a heater outside the tubing but also installing a heater at the bottomhole [12]. An electric trace heater which is attached on the outer wall of the tubing introduces heat to the inside of the tubing to control the outbreak of paraffin, asphaltene, sulfur, hydrate and other precipitates [13].…”

Section: Flowing Improvement Techniques In Severe Cold Regionmentioning

confidence: 99%

“…An electric trace heater which is attached on the outer wall of the tubing introduces heat to the inside of the tubing to control the outbreak of paraffin, asphaltene, sulfur, hydrate and other precipitates [13]. This technique with an electric submersible pump (ESP) was announced as a general method in Northern Alaska [12]. Downhole heating technique is the way to increase oil production by installing a heater at the bottomhole.…”

Section: Flowing Improvement Techniques In Severe Cold Regionmentioning

confidence: 99%

Analytical study on the optimum design of producing well to increase oil production at severe cold regions

Sung

Kwon

Kim

et al. 2010

Korean J. Chem. Eng.

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This paper presents a simulation study of fluid flow in the tubing on a reservoir system formed in a severe cold region. The thickness of the permafrost and specific gravity of the oil were applied by field survey. Then, flowing improvement techniques for oil production such as progressive cavity pump (PCP), insulated casing, electric trace heater and gas lifting were applied. For the reservoir located at 1,000 m depth in the Arctic region, the thicker the permafrost layer was, the more the mobility of oil in the tubing declined. By applying the flowing improvement techniques to this reservoir, the effect of the heater increased with the oil containing heavier components, and it was found that the production rate was improved as the heater installation interval became deeper. Despite the gas lifting method showing better productivity compared to other methods, there was an optimal injection rate at which the production rate became maximum. Moreover, it was shown that increasing the temperature of injection gas had little effect on enhancing the oil flow in tubing. Based on these results, flowing improvement techniques were applied to the oil wells in the Ada field. The productivity by PCP of Bashenkol_1X well, which contained comparatively light oil, increased 3.75 times more than natural state. Also, additional installation of insulated casing could yield better production. In the case of Bashenkol_3X in which 19.2 o API of heavy oil was reserved, oil production was impossible without flowing improvement methods. This well was able to produce 158 BOPD of oil by installing PCP with insulated casing and additional installation of heater increased production rate to 267 BOPD. Meanwhile, although the gas lifting method can greatly improve productivity, the applicability and cost should be considered prior to its being applied.

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First Surface Driven PCP Application on Alaska’s North Slope

Young¹,

Mathews²

2010

All Days

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Alaska's North Slope (ANS) contains a large resource of heavy oil above two of the largest producing fields in North America, but due to the complexity of producing heavy oil in an arctic environment, remains untapped. Development of heavy oil in the Arctic represents a significant departure from conventional oil developments on the North Slope as well as established heavy oil developments elsewhere in the world. This paper describes a cold heavy oil production with sand (CHOPS) test using a surface driven progressive cavity pump (PCP) to evaluate the resource for commercialization. Despite success using this technique in other heavy oil applications, significant design challenges remain. The test recovered significant quantities of oil and sand at minimal drawdown; however, the capacity of the well was limited by surface torque values that were significantly higher then anticipated and ultimately resulted in a rod failure after 3-weeks of production. Further analysis indicated that torque was dominated by drag forces between the continouous rod string and the oil. Followup testing using oil produced from the well was completed with specially designed test equipment to identify the source of the unexpectedly high torque and provided data to improve rod torque prediction. As a result of the work performed, the remaining three wells in the initial pilot were designed with significant upside in capacity.Due to restrictive surface locations and permafrost, effective solids transport in deviated wellbores and its effect on equipment wear are key considerations that need to be better understood.

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Application of Downhole Electric Heat Trace System in Arctic Completions

Cited by 4 publications

References 0 publications

Supporting Technology for Enhanced Oil Recovery-EOR Thermal Processes Report IV-12

Supporting Technology for Enhanced Oil Recovery-EOR Thermal Processes Report IV-12

Analytical study on the optimum design of producing well to increase oil production at severe cold regions

First Surface Driven PCP Application on Alaska’s North Slope

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