The diatomite reservoir in the Belridge field, California, has been undergoing water injection for pressure maintenance to mitigate reservoir compaction and improve oil recovery. The reservoir is over one thousand feet thick with multiple layers, high compressibility, and very low permeability. Accurate placement of injection water across this massive reservoir is essential for balancing layer by layer voidage and reducing compaction. Therefore, monitoring sub-surface injection profile has become an important part of diatomite waterflood surveillance. However, monitoring profile with conventional wireline radioactive tracer tools has proven to be challenging due to the inability to access wellbores for logging because of scale build-ups or casing deformations.Over the past several years, a number of field trials have been performed to see if injection profile could be monitored using distributed temperature sensing (DTS) fiber-optic technology. If the technology works, then the strategy would be to install the DTS fiber early in the life of a well while the whole wellbore was still accessible. Once the fiber was in place, dynamic monitoring of injection profile could continue even if the well later developed scale build-ups, dog-legs, or other obstructions.Initial tests at Belridge were done with the DTS cable temporarily deployed on slickline. Once it was established that DTS could be used to measure injection profile in diatomite, several permanent installations were made in different areas of the field and in injectors with different mechanical configurations. Also, three different analysis methods were tried: stabilized injection; thermal restoration; and thermal tracer. In all cases, DTS-derived injection profiles were compared against wireline radioactive tracer profiles run at about the same time and under similar injection rates and pressures. Based on the technical success of the pilot, it was decided to scale-up to a 25-well program prior to full-field implementation in all 1000+ injectors in Belridge. This scaled-up program was focused on retrofitting DTS in existing injectors that still have an unobstructed well bore. These installations required the DTS cable to be run inside the injection tubing to the current effective depth of the well. However, the presence of the fiber-optic cable inside the tubing made the well unserviceable for future interventions such as coil-tubing clean-out, stimulation, or cased-hole logging operations. For this reason, design work is currently under way to run the DTS cable outside the injector casing at the time of initial drilling and completion of the well.This paper is a case study of the application of a new technology in solving surveillance issues in an old field. It covers the slow but methodical implementation of the DTS project, the challenges, and our solutions. It presents many examples of injection profiles derived from DTS measurements and a comparative evaluation of different interpretation techniques. The learnings from this project have potential for app...

The Diatomite reservoir at the giant Belridge field, California, has been undergoing water injection for pressure maintenance to mitigate reservoir compaction and improve oil recovery. Accurate placement of injection water across this 1500 feet thick reservoir is essential for balancing voidage and reducing in-situ compaction. However, monitoring injection profile using conventional Radio-Active Tracer (RAT) technology has been a challenge due to the inability to access wellbores for logging because of scale build-ups and casing deformations.Field tests with Fiber-Optic Distributed Temperature Sensing (DTS) confirmed that the technology had the potential to replace the RAT for continuous monitoring of injection profile. However, moving from a successful pilot to full field implementation faced numerous challenges both technical and economic.To begin with, the wellbore had to be free of any restrictions for logging, stimulation, or workover activities. This meant that the fiber needed to be deployed outside the casing and cemented in place without creating a micro-annulus. The fiber and its control line also had to be installed in a way that would permit perforation for completion without damaging the fiber. Another installation challenge was to pull the control line and fiber through the wellhead mandrel, and secure the fiber from damage during rig move-out, and installation of the well-head and injection manifold.After these technical challenges were overcome, the operational challenge was how to make the whole installation procedure simple and fast enough to be integrated into Aera's lean manufacturing style of drilling process that takes less than three days to complete a well from spud to rig release.After resolving the technical and operational issues, the remaining and bigger challenge was how to make the acquisition and interpretation of this new DTS technology for monitoring of injection profile cheap enough to be incorporated in a "low-cost" environment where a producer makes less than 20 BOPD. With the potential for hundreds of injectors to be surveyed and analyzed each year, the cost breakthrough came when Aera decided to acquire its own profile surveys and develop its own software for processing and interpreting the data.A five-well permanent installation pilot followed by a 30-well survey acquisition program, and eventual development of data processing/interpretation software were successful in meeting the technical and economic challenges. The injection profiles from over 70 injection strings with DTS fibers are now being routinely surveyed and the interpreted results are being proactively used for waterflood surveillance and optimization. A 60-well per year program is currently in progress with plans for continued expansion in future years. This paper shows how innovative ideas and persistence can overcome technical and economic hurdles that often make new technologies unfeasible for old fields. The learnings from this project have potential application in converting low-cost brown fields to the di...

Operators including Aera Energy LLC are evaluating distributed temperature sensing (DTS) systems as an alternative to production logging tools (PLT) and radioactive tracer surveys (RTS) for the determination of zonal allocation factors. If DTS data can be interpreted to provide wellbore velocities, zonal allocation can be determined without well entry and practically in real-time. In comparison to PLT and RTS, DTS could provide zonal allocation at a higher measurement frequency, lower cost, and lower risk to personnel, environment, and the well asset. In wells where casing deformation precludes wireline operations, DTS may be the only viable alternative. The purpose of this work is to investigate whether water injection zonal allocation can be derived from DTS data acquired in thermal tracer injection tests within an uncertainty comparable to RTS. Three waterflood injection wells with RTS and DTS data in Aera Energy"s Belridge field in California are analyzed. The zonal allocation factors derived from the DTS are shown to agree within uncertainty with the RTS-based results. The DTS for two of the wells is interpreted through history matching with an OLGA thermal-fluid model. The DTS for a third well is interpreted using the Temperature Inflection Point (TIP) thermal tracer method proposed in this work. The TIP method is a simpler alternative to history matching and was shown to be theoretically valid for wells with negligible heat transfer at the walls over the duration of the injection test. In this regard the TIP method is less restrictive than the Slopes method, which is currently used in industry but theoretically requires negligible heat transfer at the walls and within the fluid. The TIP method is also shown to be more consistent with the field data of this study. The paper concludes with guidelines on the design and implementation of thermal injection tests and TIP analysis. The most significant practical limitation of the TIP method is its sensitivity to noise in the data, motivating DTS acquisition at the maximum practical resolution, data smoothing, and averaging over multiple test realizations.

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There are not many oil reservoirs in the world with permeabilities less than 1 md that are under waterflood. Aera Energy's Diatomite reservoir at Belridge field in California is one of the few: a massively thick reservoir, with very low permeability, very high porosity, and high rock compressibility that has been undergoing water injection for pressure maintenance for over 20 years.Optimizing subsurface injection conformance, or injection profile, is the key to operating a successful waterflood in the Diatomite. However, because of wellbore obstructions, the majority of Diatomite injectors are not accessible to conventional radioactive tracer tools for monitoring injection profile. Without a good understanding of vertical profile, it is difficult to balance voidage on a layer by layer basis. Failure to maintain good zonal pressure support can result in poor vertical sweep, as well as reservoir compaction that can lead to irreversible permeability reduction and productivity impairment.Due to reservoir compaction and elevated rate of well failures, sustaining Diatomite production requires continuous drilling of replacement and infill wells at very close well spacing (20-50 ft). Aggressive replacement drilling programs (300 wells per year) have made it possible to run open-hole Wireline Formation Tests (WFT) in sufficient density over time to effectively monitor vertical and areal pressure profiles. As a result, reservoir intervals lacking injection support have been identified for optimization.Between 2003 and 2008, Aera ran over 300 open-hole WFT surveys in the South Grande area at Belridge field, vertically covering the Opal-A and upper Opal-CT reservoirs. Large-scale pressure testing has aided in pressure maintenance operations by improving completion strategy in new injection strings, targeting differentially depleted zones. This has improved overall layer voidage profiles, as evidenced by lower producing GOR and greatly reduced occurrence of producerfailures. WFT surveys continue to serve in a feedback loop to optimize injection target setting, voidage management, and strategy for completing replacement wells. This paper reports on the innovative use of wireline formation testing to optimize water injection pressure maintenance in a major onshore waterflood, with the unique challenge of not being able to monitor injection profile in a majority of wells. The learning may apply to other tight, light oil waterfloods.