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

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.