Reservoir developments that rely on long horizontal wells are common practice. Understanding the inflow distribution from a horizontal well is an ongoing challenge for our industry. The effectiveness of reservoir management decisions are greatly improved with an understanding of the flow distribution across the reservoir interval. While technologies have been developed using tractors or coiled tubing to deploy production logging tools into horizontal wells, it requires a well intervention operation, increases risk exposure and is not always successful. This paper reviews a case study from a multi-lateral well in Alaska where a new style of chemical tracers embedded into the completion equipment was used to derive a quantitative estimate of the inflow distribution in a dual horizontal, multi-lateral well. The chemical tracers, which resemble strips of plastic, are designed to release unique chemical fingerprints when contacted by oil. The tracers are then detected in the oil to concentrations as low as 1 part per trillion. In this case study six locations were selected for placement of oil sensitive tracers. During a shut-in period the strips continue to release their unique chemical tracers causing an increased tracer concentration to develop in the oil immediately surrounding the tracer location. Upon start up, these small volumes of oil, containing the higher concentration of tracer, are displaced to the surface. Samples of the produced oil are analyzed to develop a plot of each tracer’s concentration vs produced volume. The arrival of the oil containing the high tracer concentration is related to the inflow distribution. This paper reviews results from a field deployment in a dual lateral well that contained 3 tracer locations in each lateral. The results from this well indicate that one lateral was producing approximately 30% more than the other lateral. Additionally the data indicates the toe of one of the laterals was a major contributor to the total well flow. This insight into the reservoir performance was obtained with no intervention into the well and only minor modifications to the completion design.
Summary The Oooguruk Unit is on a man-made gravel island in the Beaufort Sea, five miles offshore the Alaskan North Slope (ANS) in Harrison Bay. The field produces from the Kuparuk, Torok, and Nuiqsut reservoirs. The focus of this paper is the Nuiqsut sandstone, which is currently undergoing water and lean-gas injection for secondary recovery. The wells are completed as 6,000- to 7,000-ft horizontal laterals aligned parallel with the preferred fracture orientation in a line-drive waterflood pattern. Recent optimizations in mechanical-diversion fracturing in these laterals have provided significant improvements in production rates, including several recent wells with initial production of more than 7,000 BOPD. This paper will document the completion and fracturing-design evolution over several vintages of wells, as well as the use of preinstalled tracer systems to verify production uniformity and diversion success. The reservoir ranges in thickness from 60 to 120 ft and is divided into several producing sand and shale intervals. The initial phase (I) of completions planned for this reservoir was to use 8,000-ft-long undulating openhole horizontal laterals. However, these were quickly abandoned after the first well collapsed in a shale section. The second phase (II) used undulating wellbores for producing wells, but were completed with preperforated pups spaced evenly throughout the uncemented liner in the horizontal section. These wells were also stimulated with dynamic-diversion fracturing treatments that used ball sealers. Because of the logistical difficulties and expense in fracturing operations on a gravel island in the Beaufort Sea, two wells were also completed during this phase as unfractured dual-laterals, but resulted in productivity similar to dynamic diversion fracturing in one well and significantly less in the second well. During these phases of increased well productivity, modifications were required to increase waterflood well injectivity, which was accomplished by implementing a system of high-pressure breakdown (HPBD) stimulations, as well as fully mechanical diversion-fracture treatments. These changes in injection-well completions will also be described in the paper. Phase II wells resulted in production improvements of nearly 100% over the Phase I completions. This led to the third phase of development, which used mechanical-diversion techniques, implemented in relatively flat horizontal laterals. This completion type allowed mechanical-diversion fracturing treatments that placed more than three times the low-density ceramic (LDC) proppant and generated wells with initial production of more than 7,000 BOPD (an additional 100% increase over Phase II completions). All future producing wells are now planned to be completed with mechanical-diversion equipment. The completion-optimization evolution described in this paper will be useful to completion and development engineers of other conventional reservoirs, and the lessons learned are already being successfully applied to another nearby ANS development.
The Oooguruk Unit is located on a man-made gravel island in the Beaufort Sea, five miles offshore the Alaskan North Slope in Harrison Bay. The field produces from the Kuparuk, Torok and Nuiqsut reservoirs. The focus of this paper is the Nuiqsut sandstone which is currently undergoing water and lean gas injection for secondary recovery. The wells are completed as 6,000 ft to 7,000 ft horizontal laterals aligned parallel with the preferred fracture orientation in a line drive waterflood pattern. Recent optimizations in mechanical diversion fracturing in these laterals have provided significant improvements in production rates including several recent wells with initial production of over 7,000 BOPD. This paper will document the completion and fracturing design evolution over several vintages of wells, as well as the use of pre-installed tracer systems to verify production uniformity and diversion success.The reservoir ranges in thickness from 60 ft to 120 ft and is divided into several producing sand and shale intervals. The initial completion type planned for this reservoir was an 8,000 ft long undulating open hole horizontal lateral. This was quickly abandoned after the first well collapsed in a shale section. Undulated wellbores continued to be drilled for producing wells but were completed with pre-perforated pups spaced evenly throughout the liner in the horizontal section. These wells were stimulated with dynamic diversion fracturing treatments. Because of the logistical difficulties and expense in fracturing operations on a gravel island in the Beaufort Sea, two wells were also completed as multi-laterals, but resulted in productivity similar to dynamic diversion fracturing in one well and significantly less in the second well.The initial move to undulated horizontal wellbores utilizing dynamic diversion fracturing treatments resulted in production improvements of nearly 100% over unstimulated wells. This led to the use of mechanical diversion techniques implemented in relatively flat horizontal laterals. This completion-type allowed mechanical diversion fracturing treatments utilizing over three times the low density ceramic proppant and generated wells with initial production of over 7,000 BOPD (an additional 100% increase over dynamic diversion fracturing). All future producing wells are now planned to be completed with mechanical diversion equipment. The completion optimization evolution described in this paper will be useful to completion and development engineers of other conventional reservoirs, and the learnings are already being successfully applied to another nearby Alaskan North Slope development.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.