Most oil wells producing from the Glauconite YY Pool of the Lake Newell field in Southern Alberta, Canada have very high flow capacities. Wellbore operations are complicated by the configuration of the slant wells with surface angles of 45 that can reach 75 at bottom and horizontal displacements in excess of 6600 ft. During the development of this field, it was determined that there was a full cycle economic advantage to utilize gas lift as the primary artificial lift scheme because of the extended reach slant wellbore configurations. In 1996 opportunities to economically enhance production and accelerate recovery were identified in several of these gas lifted wells. Wellbore performance could not be matched to any theoretical tubular flow simulation thus a significant effort was made to understand these differences which, after consultation with various international experts, still did not offer a definitive explanation. Some of the production impairment mechanisms considered were phase separation and stratification of fluids (water, oil, and gas) in the tubing, wax/paraffin formation, and unknown fluid rheologies. An attempt to production log one well was unsuccessful because the well ceased to produce with the decreased flow diameter of coiled tubing inside 2.875 inch production tubing. Since some wells are producing at drawdowns as low as 5%, significant production enhancement opportunities still needed to be pursued along with identifying the welibore production impairment mechanism. Larger diameter tubing (3.5 inch) was run in a 70% water cut well increasing production from 850 BLPD to 1130 BLPD, which was still significantly lower than theoretical rates of 3150 BLPD. A demulsifier chemical, that the cross functional property team had previously identified as being effective in reducing high pressure drops in surface piping, was introduced into the injection gas stream. Two days after chemical injection began, the well started to produce at theoretically predicted production rates; however, it was very unstable and would cycle to original rates for long periods of time followed by very high rates again due to changing annular fluid levels. This prompted the installation of a chemical injection capillary tubing to bottom resulting in sustained production of 3000 BLPD: a 150% increase and near the theoretically predicted rates. This paper will sequentially outline the diagnostic and operational methodology used to solve the very difficult problems encountered with unconventional wellbores and fluids. It will emphasize the value of teamwork in problem resolution and demonstrate that perseverance in working through a problem or issue follows a modified Shewhart Cycle. The well improvements outlined in this paper have significantly contributed to enhancing the economic oil recovery of the YY Pool. P. 67

A new corrosion inhibitor that can reduce oil in water (OIW) was selected for use in a field offshore on Australia's North West Shelf. The selected product has allowed the achievement of the new stewardship OIW target of 17.5 ppm, enabling improvements in overall environmental impact. Laboratory tests showed that the selected product had similar corrosion inhibitor performance to the incumbent field product. Meanwhile, laboratory OIW measurements showed that 50 ppm of the selected product generated significantly less OIW (17 ppm OIW compared to 159 ppm OIW with 50 ppm of incumbent product). On-site tests were then performed with fresh produced fluids, demonstrating again that the selected product resulted in lower OIW (a 42%, 43% and 73% OIW reduction compared to incumbent product, at 20, 30 & 40 ppm of corrosion inhibitor, respectively). A full-field trial immediately demonstrated a decrease in OIW results corresponding to a decrease in overboard OIW from a daily average of 20.0 ppm to 8.8 ppm during the trial period, with no adverse impact on corrosion probe readings. The new product has now been in use on this facility for 10 months. Corrosion monitoring continues to show good inhibition while the OIW levels remain below 16 ppm average, and concurrently is allowing a reduction in the use of associated water treatment chemicals, further benefiting the environment.

Most oil wells producing from the Glauconite YY Pool of the Lake Newell field in Southern Alberta, Canada have very high flow capacities. Wellbore operations are complicated by the configuration of the slant wells with surface angles of 45° that can reach 75 ° at bottom and horizontal displacements in excess of 2000 m. During the development of this field, it was determined that there was a full cycle economic advantage to utilize gas lift as the primary artificial lift scheme because of the extended reach slant wellbore configurations. In 1996 opportunities to economically enhance production and accelerate recovery were identified in several of these gas lifted wells. Well bore performance could not be matched to any theoretical tubular flow simulation thus a significant effort was made to understand these differences which, after consultation with various international experts, still did not offer a definitive explanation. Some of the production impairment mechanisms considered were phase separation and stratification of fluids (water, oil, gas) in the tubing, wax/paraffin formation, and unknown fluid rheologies. An attempt to production log one well was unsuccessful because the well ceased to produce with the decreased flow diameter of coiled tubing inside 73 mm (2.875 inch) production tubing. Since some wells are producing at drawdowns as low as 5%, significant production enhancement opportunities still needed to be pursued along with identifying the wellbore production impairment mechanism. Larger diameter tubing (89 mm - 3.5 inch) was run in a 70% water cut well increasing production from 135 m3/D (850 BPD) to 180 m3/D (1130 BPD) which was still significantly lower than theoretical rates of 500 m3/D (3145 BPD). A demulsifier chemical, that the cross functional property team had previously identified as being effective in reducing high pressure drops in surface piping, was introduced into the injection gas stream. Two days after chemical injection began, the well started to produce at theoretically predicted production rates; however, it was very unstable and would cycle to original rates for long periods of time followed by very high rates again due to changing annular fluid levels. This prompted the installation of a chemical injection capillary tubing to bottom resulting in sustained production o 480 m3/D (3019 BPD) which is a 150% increase and near the theoretically predicted rates. This paper will sequentially outline the diagnostic and operational methodology used to solve the very difficult problems encountered with unconventional wellbores and fluids. It will emphasize the value of teamwork in problem resolution and how automated monitoring can greatly enhance the analysis of all information and situations. It will briefly address the surface system debottlenecking and optimization. The well improvements outlined in this paper have significantly contributed to enhancing the economic oil recovery of the YY Pool.

There is a growing demand for digital solutions to improve efficiency of oil & gas processing. The ultimate goal is digital platforms that connect multiple information sources, both software and hardware, to make better operational decisions and dramatically improve efficiency. Development of these holistic platforms is still relatively new, although various smaller applications of data digitization and equipment automation do exist. In this paper three field cases will be given to demonstrate the powerful benefits of data digitization and automation. Field Case 1 describes a data management tool that connects field data with SAP and LIMS. The customizable surveillance screens refresh with new laboratory data as soon as they are uploaded in LIMS, and show how water composition trends in relation to corrosion coupons help to optimize costs for corrosion inhibitor. Field Case 2 describes a completely autonomous injection skid to mitigate H2S in a well that requires periodic intervention for paraffin treatment. A scavenger is injected downhole at a dosage rate that is determined by real-time H2S analysers coupled with production flow data, and maintains a zero concentration of H2S at the well head. This novel solution improves personnel safety by enabling work-over crews to work under less hazardous conditions. Field Case 3 describes an automated system for a refinery cooling water system, where a single controller orchestrates five chemical injection pumps based on real-time input from multiple analysers and sensors. From these field cases it can be concluded that digitization and automation tools provide easy, cost- effective and powerful solutions to improve efficiency in oilfield operations. It enables field operators and managers to focus on value adding tasks. When the vast downstream experience of using sophisticated controllers, sensors and analysers is applied to upstream environments efficiency in oil & gas processing facilities can be further improved with lower human intervention.

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