Hydraulic Fracturing at the Inglewood Oil Field
The difference between the fracking technologies of Hi Rate-Gravel Pack, Conventional Fracking, and High Volume Hydraulic Fracking (HVHF), and how they have been used in the Inglewood oil field are explained in these edited excerpts from the 1/10/2012 Hydraulic Fracturing Study. All edits and formatting are for brevity and simplification, please refer to the source material for full text content.
PXP conducted 2 High-Volume Hydraulic Fracturing (HVHF) tests at two wells at the Inglewood Oil Field.
Conventional hydraulic fracturing has been conducted on 21 wells at the Inglewood Oil Field. These were conducted in the Sentous Moynier, Bradna, City of Inglewood, Rubel, and Nodular shale formations. Combined, a total of approximately 65 stages of conventional hydraulic fracturing have occurred at the Inglewood Oil Field since 2003 when PXP began operating the field, in 2003.
PXP has conducted high-rate gravel pack completions on approximately 166 wells in the Inglewood Oil Field. Each high-rate gravel pack includes an average of five stages per well; therefore, approximately 830 stages have been completed at the Inglewood Oil Field since 2003.
Data prior to 2003 is not available.
Figure 3-4 shows the location of Inglewood Oil Field wells that have had high-volume hydraulic fracturing (HVHF) or conventional hydraulic fracturing since PXP took over field operations. All of the frack jobs been completed on pumping wells rather than injection wells.
Hi Rate- Gravel Packs
3.3.1 High-rate gravel packs were first used in 2003 and since then, and up to the study date, over 830 instances have been performed. This technique was the first to exceed the fracture gradient in the surrounding formation. The fractures would typically be less than 250 feet from the well. Eleven of the completions in 2004 used crude oil in the fluids. The crude oil had been previously pumped from the formation, and was only used for high-rate gravel packs targeting the oil producing zones- never above, or near, the base of fresh water.
|Parameters||High-Rate Gravel Pack||Hydraulic Fracturing|
|Pump Time (minutes)||27.68||141.87|
|Clean Volume (bbl)||418.45||2992.18|
|Slurry Volume (bbl)||458.89||3210.35|
|Average Treating Pressure (psi)||768||6914|
|Max Treating Pressure (psi)||1343||8818|
|Proppant Mass (100* lb)||373.79||2013.48|
3.3.2 Recent High-Rate Gravel Pack Completions
PXP also conducted high-rate gravel pack jobs at two wells on the Inglewood Oil Field to assess feasibility and potential impacts. The first high-rate gravel pack involving a five-stage completion was conducted on January 9, 2012, at the TVIC-221 well. The second high-rate gravel pack involved a six-stage completion and was conducted on the same day at a different well, TVIC-3254. Both of these operations were conducted in the Vickers and Rindge formations. The high-rate gravel pack operations were conducted by Halliburton with PXP oversight. The conditions of the high-rate gravel packs are similar to the well completions previously conducted across the field, and are also similar for any future high-rate gravel pack jobs that would be expected to be conducted at the oil field.
The maximum applied pressure during both high-rate gravel packs was 1,900 psi. In comparison the high-volume hydraulic fracturing projects had an average treatment pressure of 2,971 psi (VIC1-330) and 6,914 psi (VIC1-635). The high-rate gravel pack fracturing influences the zone within 100 to 250 feet of the well within the target oil-producing zone, compared to in excess of 500 feet for hydraulic fracturing.
3.4 Anticipated Future Use of Hydraulic Fracturing and Gravel Packing at the Inglewood Oil Field
PXP expects that, in the future, high-volume hydraulic fracturing and conventional hydraulic fracturing may be conducted in the relatively deep Rubel, Moynier, Bradna, City of Inglewood, Nodular, and Sentous zones (all located deeper than 4,000 feet below ground surface).
It is anticipated that high-rate gravel packing operations may be conducted on as many as 90 percent of all future production wells drilled in the Vickers and Rindge formations on the Inglewood Oil Field, as well as other permeable sandstone completions. This procedure results in less formation sand being drawn into the well during pumping, thus, the amount of formation sand that requires management at the surface is reduced and the procedure provides a longer life to the well.
3.2.2 High-Volume Hydraulic Fracturing (HVHF)
PXP contracted Halliburton Energy Services to conduct 2 test high-volume hydraulic fracture jobs at separate wells on the Inglewood Oil Field. The first frack job was on September 15 and 16, 2011, at the VIC1-330 well. The second on January 5 and 6, 2012, at the VIC1-635 well. Only one hydraulically fractured stage was completed on each well. Both were conducted in the Nodular Shale, a subunit of the Monterey Shale, approximately 8,000 to 9,000 feet below ground surface.
“Halliburton (2012) contains a full report of these operations. The conditions of the hydraulic fracture jobs are the same as those expected for any other future high-volume hydraulic fracturing to be conducted at the field. Therefore, the applied pressure, water use, and monitored effects are expected to be similar between these two stages of high- volume hydraulic fracture jobs and any future stages of high-volume hydraulic fracture jobs”.
Future high-volume hydraulic fracturing completions would likely utilize more than one stage per well in the future. In hydraulic fracture jobs that consist of more than one stage, each stage would be conducted one after the other. Cumulatively, the amount of water and chemicals used would be greater for a multi-stage completion than for a single-stage completion. Although VIC1-330 and VIC1-635 are both vertical wells, PXP reports that in the future, high- volume hydraulic fracturing may be conducted via horizontal wells…
Water and Chemical Use during High-Volume Hydraulic Fracturing
Water Use and Source
Water for the hydraulic fracturing operations at the Inglewood Oil Field is provided from either produced water the field or, if a potassium chloride gel is used, fresh water provided by California American Water Company, the provider of all fresh water used at the Inglewood Oil Field. For both of the high-volume operations on the field, PXP used fresh water. Table 3-1 provides the volumes of water used during the high-volume hydraulic fracturing at the Inglewood Oil Field.
|Operation Type||Date||Well||Volume Water Used(gallons)||Water Source|
|High Volume||September 15-16 2011||VIC1-330||123354||Fresh Water|
|High Volume||January 5-6 2012||VIC1-635||94248||Fresh Water|
Water produced during hydraulic fracturing operations, known as flowback water and flush water, is transported by pipeline to the field water treatment plant where it is mixed with other produced water generated on the field. The treated water is then reinjected into the oil and gas producing formations as part of the waterflood process. This operation is in accordance with CSD Condition E.2.(i), which requires that all produced water and oil associated with production, processing, and storage be contained within closed systems at all times. The volume of water in the oil and gas producing zones is much greater than the volumes used for hydraulic fracturing and as such any residual additives are greatly diluted. In addition, many of the chemicals are soluble in oil and would be removed from the subsurface when the oil is sold.
Table 3-2 lists the additives that were mixed with the water and sand and injected into the formation during the two high-volume hydraulic fracture operations at the Inglewood Oil Field. Please refer to Appendix B for more detailed information regarding these additives, including volume injected and concentration.
|Additive Type||Trade Name||Typical Main Compound Listed on MSDS||Purpose|
|Water||Water||Base fluid carries proppant- also can be present in some additives|
|Biocide||BE-3S||Propionamide||Prevents or limits growth of bacteria which can cause formation of hydrogen sulfide and physically plug flow or oil and gas into the well|
|Gel||LGC-38 UC||Guar Gum/Naptha hydrotreated heavy||Thickens the water in order to suspend the sand|
|Breaker||SP Breaker||Sodium Persulfate||Allows for a delayed breakdown of the gel|
|Crosslinker||BC-140||Borate||Maintains fluid viscosity as a temperature increases|
|pH Adjusting Agent||MO-67||Sodium Hydroxide||Adjusts pH to proper range for fluid to maintain the effectiveness of other fluid components|
|Surfactant||Losurf-300M||Ethanol||Aids in recovery of water used during fracturing operation by reducing surface tension|
|Clay control||Clayfix II Plus||Alkylated quaternary chloride||Clay-stabilization additive which helps prevent fluid interaction with formation clays|
|Potassium chloride||Proppant||Silica||Holds open fracture to allow oil and gas to flow to well|