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...
Fluid flow in light, tight oil (LTO) reservoirs is by nature capillary-force dominated, as opposed to viscous-force dominated. However, most LTO reservoir models rely solely on well-log data to initialize volumes of original hydrocarbons in place, ignoring the physics of capillarity. This reliance on well logs owes to the difficulty of generating accurate, core-derived saturation height function models (SHFM). Moreover, when initializing reservoir saturation distributions to drainage capillary pressure curves, the resulting dynamic model must then obey matrix fluid transport, which is governed by oil-water capillary pressure relationships. This often creates difficulty in the history matching process for numerical simulation models that must honor production data. A contradictory approximation of "zero capillary pressure" is often made for simplification. We successfully constructed a core-derived SHFM and matrix permeability model for the Lower Etchegoin/Williamson reservoir at the Lost Hills field, California. This unconventional reservoir contains light oil (20 to 25° API) with low matrix permeability (0.05 to 10 md). The SHFM and matrix permeability models were constructed using routine and special core analyses from three wells that were cored and logged. High pressure mercury injection (HPMI) capillary pressure measurements were acquired on 16 core-plugs taken across the three main reservoir zones. From capillary pressure analyses, a Williamson SHFM was generated based on best-fits of irreducible water saturation, capillary entry-pressure, Brooks-Corey exponent, and permeability/porosity combinations. A single free water level (FWL) parameter was tuned in the SHFM at each of the well locations to force a match with the resistivity-derived saturation profiles. An excellent match of the saturation profile for the three wells was achieved. Unexpectedly, the Williamson SHFM has also proven useful in identifying the presence of geologic faults, independent of logs and seismic. When the capillary pressure model was applied to step-out areas, requiring a ‘depth offset’ correction to maintain a constant FWL across fault blocks (relative to the main reservoir block FWL), it was successfully hypothesized that faulting was present. The ‘depth offset’ correction represents the overall vertical fault displacement between reservoir blocks.
It sounds like a contradiction -assessing waterflood oil recovery by layer in a reservoir without knowing the original saturation distribution. However, we have developed a new method for estimating layer oil recovery efficiency using nuclear magnetic resonance (NMR) and dielectric logs run in wells within a mature, onshore waterflood. We use post-waterflood NMR T2 signals to give the reservoir rock pore-body size distribution at depths along the wellbore. This depth-dependent distribution can be converted into a series of oil-water capillary-pressure curves. The capillary pressure curves can then be modeled into the original, pre-waterflood saturation height model (SHM), which gives original oil in place (OOIP). The dielectric log, also acquired postwaterflood, is used to measure the remaining oil distribution in the reservoir. The breakthrough concept is that the saturation difference between the NMR-derived saturation height model and the post-waterflood dielectric log, which corresponds to the amount of oil swept by the flood, can be measured post-waterflood "all in one go."Conventionally, pre-primary recovery well logs are needed to delineate native-reservoir saturation distributions and provide a baseline for OOIP. Although ~1500 resistivity well logs were acquired in the diatomite reservoirs of the South Belridge field in the San Joaquin Valley, California, between 1979 and 1987, our understanding of localized original saturation variations is complicated by many factors. These include primary depletion and the injection of variable salinity water over time. For these reasons, this "all in one go" alternative method was developed to estimate OOIP and waterflood sweep efficiency in the diatomite.The biggest test of this new technique came when comparing the OOIP calculated from the NMR-inferred capillary pressure model against the existing geologic model (localized averages of early well logs) used for the South Belridge field. We found that the OOIP calculated by the new technique agreed favorably with that calculated by the existing geologic model. As a result, a re-assessment of sweep efficiency in the multi-layered South Belridge waterflood is being undertaken on a layerby-layer basis. This new, post-waterflood NMR and dielectric logging assessment of sweep has potential applications to other reservoirs.
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