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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.

Coiled tubing fracturing has been successfully applied in multi-stage vertical well stimulation in the Belridge diatomite in the Lost Hills field. This same methodology was used to complete two northwesttrending horizontal wells drilled on the northeast flank of the Lost Hills anticlinal structure that targeted thinner higher oil-saturation strata, separated by thicker low oil-saturation intervals. The target reservoir is comprised of high porosity, low matrix permeability Opal A diatomite.The perforations were jetted by pumping sand slurry down the coiled tubing and the frac job was pumped down the annulus. The stages were isolated by setting sand plugs. Nine and twelve stages were pumped in the two wells respectively. The perforation locations for different stages were selected in areas with: 1) high resistivity and inferred high oil saturations, 2) absence of hydraulic fractures from nearby wells, 3) excellent cement bonding, and 4) low intensity of natural fractures. These assessments followed logging while drilling (LWD) gamma ray, induction resistivity and azimuthally focused resistivity (image) logs and cased-hole ultrasonic image tool (USIT) run with the aid of a tractor. The hydraulic fractures were monitored using surface tiltmeter sensors. Oil and water soluble tracers were pumped to determine the relative production contribution from the stages and fracture fluid cleanup, respectively, from the stages. All the jobs could be successfully pumped without any screen outs. Challenges were faced in setting sand plugs and isolating stages. Large fracture widths and low leak-off into the formation led to difficulty in forming sand bridges at the perforations and concentrating sand in the wellbore for the plugs. Surface tiltmeters showed excessive fracture height growth. Tracer results showed that 20-30% of the stages contributed to 50-60% of the production. Stages with higher treating pressures contributed less towards production. This could be attributed to near wellbore tortuosity in these stages. Proppant flowback was encountered in one well, and after an effective clean up the production rose.The study illustrates how integration of various aspects such as completion design, fracture pressure analysis and diagnostics combined with geologic and reservoir information can help in identifying challenges and finding potential solutions of hydraulic fracturing. The findings highlight that the technology most suitable for vertical well stimulation might not be favorable for horizontal well stimulation.

Summary Coiled-tubing (CT) fracturing has been applied successfully in multistage vertical-well stimulation in the Belridge diatomite in the Lost Hills field. This same methodology was used to complete two northwest-trending horizontal wells drilled on the northeast flank of the Lost Hills anticlinal structure that targeted thinner, higher-oil-saturation strata separated by thicker lower-oil-saturation intervals. The target reservoir presents high-porosity, low-matrix-permeability, and low-Young's-modulus Opal A diatomite. The perforations were jetted by pumping sand slurry down the CT, and the fracture job was pumped down the annulus. The stages were isolated by setting sand plugs. Nine and twelve stages were pumped in the two wells, respectively. The perforation locations for different stages were selected in areas with high resistivity and inferred high oil saturations, an absence of hydraulic fractures from nearby wells, excellent cement bonding, and low intensity of natural fractures. These assessments followed logging-while-drilling (LWD) with gamma ray, induction-resistivity and azimuthally focused resistivity (AFR) (image) logs, and a cased-hole ultrasonic image tool (USIT) run with the aid of a tractor. The hydraulic fractures were monitored by use of surface tiltmeter sensors. Oil- and water-soluble tracers were pumped to determine the relative production contribution from the stages and fracture-fluid cleanup, respectively, from the stages. All the jobs could be pumped successfully without any screenouts. Challenges were faced in setting sand plugs and isolating stages. Large fracture widths and low leakoff into the formation led to difficulty in forming sand bridges at the perforations and concentrating sand in the wellbore for the plugs. Surface tiltmeters showed excessive fracture-height growth. Tracer results showed that 20 to 30% of the stages contributed to 50 to 60% of the production. Stages with higher treating pressures contributed less toward production. This could be attributed to near-wellbore tortuosity in these stages. Proppant flowback was encountered in one well, and after an effective cleanup, the production rose. The study illustrates how integration of various aspects, such as completion design, fracture-pressure analysis, and diagnostics, combined with geologic and reservoir information can help in identifying challenges and finding potential solutions for hydraulic fracturing. The findings highlight that the technology most suitable for vertical-well stimulation might not be favorable for horizontal-well stimulation.