Turn Down the Burner: Impact of Heat Management on the Potter Reservoir, MWSS Field, California

Abstract

Abstract In November, 2000, prompted by extremely high natural gas prices, steam injection was reduced by 78,000 BSPD (60%) for an extended period in the Potter Reservoir of the MWSS Field located in California. The price environment served to accelerate efforts to reduce injection to the thermodynamic minimum. Production decreased by around 5000 BOPD (SOR ~ 18:1). The Potter formation is a steeply, dipping sandstone reservoir containing 13° API oil and has been under thermal recovery for over 30 years. An extensive surveillance network of observation wells allowed for gathering of high quality heat and reservoir fluid information. This paper will discuss the theory and approach taken to set lower steam targets. It will also show examples of the impact of lower steam rates on thermally mature properties. Additional unresolved issues concerning our current inability to fully understand the relationship between reservoir (or steam chest) temperatures and oil production rates will also be discussed. Introduction The Midway-Sunset oilfield is located along the southwestern edge of the San Joaquin Basin (Figure 1). This field is about 3 miles wide and over 25 miles long. During 2001, the Midway-Sunset field was the largest oil producer in California. Although the field is composed of a number of separate pools in different stratigraphic horizons, most of the current production comes from Upper Miocene age sands within the Reef Ridge Shale that are informally named the Potter sands. The main Potter sand pool is found in the northwestern part of the Midway-Sunset field area and covers about 8.2 square miles. The Potter formation is a steeply, dipping sandstone reservoir containing 13° API oil and has been under thermal recovery for over 30 years.The reservoir has been under active thermal recovery since 1964. After a substantial re-development program begun in 1998, production peaked in this area of Midway Sunset Field in 2000.Steam injection also reached a maximum rate.Beginning in late 1998, a team of engineers began reviewing heat management practices with the goal of implementing best practices. Their recommendation to reduce steam injection to the thermodynamic minimum was presented to Management in September, 2000. Natural gas prices began to significantly increase shortly after the release of the study. In response to the study's recommendations and high gas prices, the steam injection rate was dramatically reduced from 130,000 BSPD to 52,000 BSPD (Figure 2). The oil production rate was impacted by the decrease in steam injection. The oil production rate was also decreased when downdip and high water cut wells were shut in due to water disposal capacity limitations. Prior to the rate reduction, the majority of the produced water was processed and used for steam generation.When the rate of steam injection was decreased, the field's water disposal became a limiting factor.Production wells with relatively high water cuts were shut-in, which impacted the oil production rate. By February 2001, additional water disposal capacity became available. All of the shut-in, higher water cut wells were returned to production. The true production impact from the steam reduction was approximately 5000 BOPD. Surveillance Surveillance is a key to effective management of a thermal project. The main areas that need to be monitored are :Reservoir condition,Production,Steam injection and Surface facilities. To be effective, data must be routinely gathered, processed, analyzed and stored.