TX 75083-3836, U.S.A., fax 01-972-952-9435.

In an attempt to improve production response, fracturing designs in the Lost Hills field went from a standard three-to six-stage design to an extreme 15-to 18-stage design to stimulate approximately 1,000 ft of net pay. The previous standard designs were becoming borderline economic, and if development was to continue, then either production response had to improve or costs had to be reduced. Previous emphasis was placed on reducing fracturetreatment costs by pumping fewer stages and lower proppant volumes, but the cumulative production response decreased as a result. Previous tests using an increased number of fracture stages did not improve economics because of the increased fracturing costs and minimal production increases. When a new coiled-tubing fracturing technique was implemented to perform multistage jobs at reduced costs and the stage count per well was increased, production response and economics improved. This paper will discuss the differences in job execution, analysis of vertical fracture coverage using surface and downhole tiltmeter data, and cumulative production response from the different designs tested. Both treatment and stage design with this fracturing technique are being refined further as the performance and statistical analysis of previous design changes are completed. Field-Development SettingA large part of California's oil production occurs in several San Joaquin Valley giant fields that have heavy oil or low permeability. These fields remain highly oil saturated (several have more than 1 billion bbl of remaining oil in place), even though they were discovered and initially developed in the early 1900s. Thermal enhanced oil recovery (EOR), waterflooding, and/or hydraulicfracturing techniques are now applied to these fields.Lost Hills is one such field; it was discovered in 1910, remains largely undepleted, and is currently near all-time high production rates because of a combination of hydraulic fracturing and waterflooding. Beginning in the late 1980s, improvements in hydraulicfracturing design and implementation yielded results that justified an aggressive diatomite primary-development-well program on 2½-acre producer spacing (Wilt and Morea 2004). Waterflooding began in the early 1990s to reduce well failures caused by subsidence and to improve recovery. The 2½-acre development program was completed in 1997, drilling approximately 60 wells per year. Beginning in 1998, infilling began to reduce production well spacing to 1¼ acres in the waterflooded area, and this program continued until it was completed in 2004. In 2001, a 5 ⁄8-acre infill pilot was installed, with the pilot being expanded in 2004 because of the encouraging initial results. In 2003, a large waterflood expansion began northward at an accelerated pace, with more than 100 wells being drilled each year until 2005, when more than 200 wells were drilled to complete the north waterflood expansion at 1¼-acre producer spacing.As with any finite natural resource, the Lost Hills field's reservoir quality varies. With developm...

In an attempt to improve production response, fracturing designs in the Lost Hills field went from a standard 3 to 6 stage design to an extreme 15 to 18 stage design to stimulate approximately 1000' of net pay. The previous standard designs were becoming borderline economic and if development was to continue then either production response had to improve or costs had to be reduced. Previous emphasis was placed on reducing fracture treatment costs by pumping fewer stages and lower proppant volumes, but the cumulative production response decreased as a result. Previous tests using an increased number of fracture stages did not improve economics because of the increased fracturing costs and minimal production increases. When a new coiled tubing fracturing technique was implemented to perform multi-stage jobs at reduced costs and the stage count per well was increased, production response and economics improved. This paper will discuss the differences in job execution, analysis of vertical fracture coverage using surface and downhole tiltmeter data, and cumulative production response from the different designs tested. Both treatment and stage design with this fracturing technique are being further refined as performance and statistical analysis of previous design changes is completed. Field Development Setting A large part of California's oil production occurs in several San Joaquin Valley giant fields that have heavy oil or low permeability. These fields remain highly oil saturated, several with over 1 billion barrels of remaining oil in place, even though they were discovered and initially developed in the early 1900's. Thermal EOR, waterflooding and/or hydraulic fracturing techniques are now applied to these fields. Lost Hills is one such field - it was discovered in 1910, remains largely undepleted, and is currently near all time high production rates because of a combination of hydraulic fracturing and waterflooding. Beginning in the late 1980's, improvements in hydraulic fracturing design and implementation yielded results which justified an aggressive diatomite primary development well program on 2-½ acre producer spacing1. Waterflooding began in the early 1990's to reduce well failures due to subsidence and improve recovery. The 2–1/2 acre development program was completed in 1997, drilling about 60 wells per year. Beginning in 1998, infilling began to reduce production well spacing to 1–1/4 acre in the waterflooded area and this program continued until it was completed in 2004. In 2001, a 5/8 acre infill pilot was installed with the pilot being expanded in 2004 due to the encouraging initial results. In 2003, a large waterflood expansion began northward at an accelerated pace with over 100 wells being drilled each year until 2005 when over 200 wells were drilled to complete the north waterflood expansion at 1–1/4 acre producer spacing. As with any finite natural resource, the Lost Hills field's reservoir quality varies. With development area expansion into the north section of the field, and the smaller waterflood infill drilling spacing, wells should have poorer economic results due to interference between wells and reduced reservoir quality. In order to compete for capital, hydraulic fracturing design optimization had to improve production response and/or reduce costs. To accomplish this, statistical (lean sigma) analysis was performed on all previous fracture design changes from 1998 through 2002. The design changes that yielded the best performance and/or reduced costs were incorporated into a 2003 standard fracture design.

fax 01-972-952-9435. AbstractWe discuss our experience to date with the Carbon/Oxygen logging technique to determine vertical sweep in Belridge Diatomite in the Lost Hills Field. We describe early interpretation challenges with overly optimistic saturation estimation. This required in-house Monte Carlo modeling to understand the tool response in very high porosity reservoirs. A newer vendor algorithm, however, underestimated the oil saturation. In-house test algorithms were then developed with significantly more accurate estimation of the oil saturation from a centralized-detector C/O tool in water-filled boreholes; results reported here are primarily for this tool. The C/O technique is also being tested in producers using the corresponding focused tool; we include an example of a successful test of the tool in an uperforated well. The paper identifies further development needed to use C/O techniques, especially the focused tool, optimally in either monitor or producer wells in diatomite.

We discuss our experience to date with the Carbon/Oxygen logging technique to determine vertical sweep in Belridge Diatomite in the Lost Hills Field. We describe early interpretation challenges with overly optimistic saturation estimation. This required in-house Monte Carlo modeling to understand the tool response in very high porosity reservoirs. A newer vendor algorithm, however, underestimated the oil saturation. In-house test algorithms were then developed with significantly more accurate estimation of the oil saturation from a centralized-detector C/O tool in water-filled boreholes; results reported here are primarily for this tool. The C/O technique is also being tested in producers using the corresponding focused tool; we include an example of a successful test of the tool in an unperforated well. The paper identifies further development needed to use C/O techniques, especially the focused tool, optimally in either monitor or producer wells in diatomite. Introduction The Belridge Diatomite in the Lost Hills Field in San Joaquin Valley, California, contains over 2 billion barrels of original oil in place (Wilt and Morea, 2004). This represents one of the largest components of the State's oil reserves estimated at over 24 billion barrels (Bopp, 2006). Figure 1 displays the location of oil fields in San Joaquin Valley with Lost Hills highlighted. The Belridge diatomite formation at Lost Hills is thick (~800 ft average), highly porous (~50% average porosity), has low permeability (~1 md average), and has average oil saturation of ~45%. The majority of production from the formation is from central Lost Hills, where recovery is obtained from a waterflood started 15 years ago. Determining aerial and vertical sweep in the diatomite water flood is of interest. Based on our success in Kern River (Badruzzaman et al., 1998; Harness et al., 1998), we have been evaluating the Carbon/Oxygen (C/O) technique which appears most promising due to its salinity independence and field-wide applicability. The earliest tests of the C/O technique in Lost Hills date back to the early 1990s's, when water flooding the diatomite was first initiated. However, C/O technology has been slow to mature in the field due to erroneous oil saturation predictions when compared to core or openhole log saturations. Ostermeier (1993) conducted tests with an older C/O tool (Hertzog and Plasek, 1979; Roscoe and Grau, 1988) in diatomite in the nearby South Belridge Field. Here, he showed that log-derived C/O ratios had a similar shape to core-derived C/O ratios but that there was an inexplicable offset, with log C/O ratio reading significantly higher. In the mid 1990's, a modern dual-detector C/O tool (Roscoe et al., 1991) produced oil saturation estimates that were often too high. Our in-house Monte Carlo modeling studies to understand this established that this was most likely due to poorly understood tool response in high-porosity diatomite. The vendor subsequently developed a high porosity correction. However, Badruzzaman et al., (2002) found that the oil saturation from the new algorithm of this tool appeared too pessimistic as did another vendor's dual-detector C/O tool (Jacobson et al., 1998) of the same vintage.