We interpreted a series of single-well-chemical-tracer-tests (SWCTTs) estimating residual oil (SORW) to base high salinity waterflood, low salinity waterflood and subsequent polymer flood conducted on a Greater Burgan well. Interpretation of the tests requires history matching of the back-production of partitioning and non-partitioning tracers which is impacted by differing amounts of irreversible flow and differing amounts of dispersion as well as the amount of residual oil.
We applied the state-of-the-art chemical reservoir simulator (UTCHEM) and an assisted history matching tool (BP’s Top-Down-Reservoir-Modeling) to interpret the tests and accurately quantify uncertainty in residual oil saturations post high salinity, low salinity, and polymer floods. Two optimization algorithms (i.e., Genetic algorithm (GA) and Particle-Swarm-Optimization (PSO)-Mesh-Adaptive-Direct-Search (MADS) algorithms) were applied to better address the uncertainty.
Our results show a six saturation unit decrease in SORW post low salinity with no change to the SORW post polymer. This is in-line with our expectations - we expect no change in SORW post-polymer as the conventional HPAM, which does not exhibit visco-elastic behavior, was used in the test. We demonstrate that history matching the back-produced tracer profiles is a robust approach to estimate the SORW by showing that three-or four-layer simulation model assumption does not change the SORW estimated. We accounted for the uncertainty in partition-coefficient in our uncertainty estimates.
We present several innovations that improve history matching back-produced tracer profiles; hence, better SORW estimations (e.g., different level of dispersivity for individual simulation layers to account for different heterogeneity level as opposed to assuming a single dispersion for all layers). We generate more robust estimates of uncertainty by finding a range of alternative history matches all of which are consistent with the measured data.
Optical fiber flatpacks, which are cable-reinforced plastic-encased fiber bundles used for local temperature and acoustic measurements, can be stressed when near a perforating gun. The fiber itself is floated in metal tubes with gel. Understanding the behavior under severe shock causes the use of potential mitigation schemes. In this work, the flatpack containing optic fibers is simulated for survivability on the casing of a perforating gun system. Using a shock hydrocode in two-dimensions (2D), a flatpack is simulated on the 5 1/2-in. casing of a 3 3/8-in. gun with a 21-g shaped charge. Effects of concrete encasement, clamps, and off-angle shots are considered. The view is in the plane of one shaped charge.
Quantitative results include pressure temporal profiles, velocity profiles, and g acceleration at the fibers. Pressure at the flatpack peak is in the hundreds to thousands of psi, and accelerations peak in the hundreds to thousands of g. Unconfined flatpacks tend to launch from the casing, while confined flatpacks tend to oscillate at their location. Pressure contour models show the shaped charge breaking into multiple pressure pulses. The primary shocks are in front of and behind the charge. Secondary pulses occur off-axis near the base of the charge and from the jet bow shock near the top of the charge. Overall comparative simulation results indicate optimum flatpack location and configuration. Novel mitigation schemes are identified and simulated. A fiber-optic flatpack has been simulated in a zero- degree loaded gun for the first time; this information helped with understanding survivability against shaped charge shocks.
Morales, Adrian (Chesapeake Energy Corp.) | Holman, Robert (Chesapeake Energy Corp.) | Nugent, Drew (Chesapeake Energy Corp.) | Wang, Jingjing (Chesapeake Energy Corp.) | Reece, Zach (Chesapeake Energy Corp.) | Madubuike, Chinomso (Chesapeake Energy Corp.) | Flores, Santiago (Chesapeake Energy Corp.) | Berndt, Tyson (Chesapeake Energy Corp.) | Nowaczewski, Vincent (Chesapeake Energy Corp.) | Cook, Stephanie (Chesapeake Energy Corp.) | Trumbo, Amanda (Chesapeake Energy Corp.) | Keng, Rachel (Chesapeake Energy Corp.) | Vallejo, Julieta (Chesapeake Energy Corp.) | Richard, Rex (Chesapeake Energy Corp.)
An integrated project can take many forms depending on available data. As simple as a horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations, to a large scale seismic to simulation workflow. Presented is a large-scale workflow designed to take into consideration a vast source of data.
In this study, the team investigates a development area in the Eagle Ford rich in data acquisition. We develop a robust workflow, taking into account field data acquisition (seismic, 4D seismic and chemical tracers), laboratory (geomechanical, geochemistry and PVT) measurements and correlations, petrophysical measurements (characterization, facies, electrical borehole image), real time field surveillance (microseismic, MTI, fracture hit prevention and mitigation program through pressure monitoring) and finally integrating all the components of a complex large scale project into a common simulation platform (seismic, geomodelling, hydraulic fracturing and reservoir simulation) which is used to run sensitivities.
The workflow developed and applied for this project can be scaled for projects of any size depending on the data available. After integrating data from various disciplines, the following primary drivers and reservoir understanding can be concluded. At a given oil price, optimum well spacing for a given completion strategy can be developed to maximize rate of return of the project. Many operators function in isolated teams with a genuine effort for collaboration, however genuine effort is not enough for a successful integrated modelling project, a dedicated multidisciplinary team is required.
We present what is to our knowledge, one of the most complete data sets used for an integrated modelling project to be presented to the public. The specific lessons from the project are applied to future Eagle Ford projects, while the overall workflow developed can be tailored and applied to any future field developments.
In this paper we describe how incorporating inter-well flow of gas tracers into a numerical simulation model of an oil producing field allowed us to improve the reservoir characterization. Gas tracers evidenced the lateral and vertical reservoir connectivity, identified preferential flow paths and eventually provided an additional tool for the dynamic history match.
The field produces light oil with the support of miscible gas injection, from a reservoir composed of two stacked fluvial sandstones units. To improve the reservoir characterization four inter-well gas tracer campaigns involving a total of 13 injector wells have been successfully completed. All these tracer injections have then been modeled at our full field numerical simulation model with the purpose of challenging the reservoir description in it. Input from this exercise have been later-on used during the construction of geomodels, benefiting from our improved reservoir knowledge.
The reservoir is composed of two units, Middle (M) and Upper (U), both deposited as laterally amalgamated fluvial channels. Both units appear as vertically separated by an impervious shale interval, only absent in 2 wells out of 30.
The shale interval was originally considered as a possible flow barrier by the earliest geological models. However, numerical simulation models were only able to replicate observed tracers arrivals when specific vertical connections existed between both units, indicating the shale interval was no as laterally continuous as formerly suspected.
History matching the tracers arrivals in the western field area was also helpful to reveal a fast gas breakthrough between wells which were aligned perpendicularly to the main channel orientation (NW-SE). This finding confirmed that this prevailing channel orientation was not the only responsible for a good reservoir communication, but also the lateral amalgamation (SW-NE) of channels was exerting a significant control in low sinuosity fluvial systems, as well as secondary flow directions in high sinuosity systems.
The improved reservoir characterization have been reflected in subsequent reservoir geological models and numerical simulators, avoiding misleading history matching solutions. Also, it is worth to note that this have had a direct impact on the gas injection strategy followed in the field.
Quite commonly interwell tracer flow is not fully incorporated into numerical simulators. This is a time consuming process, which, in addition to the conventional model uncertainties, requires sensitivities to the associated tracer parameters. This paper demonstrate through a real case how valuable this additional effort may result, and how it may improve the geological and dynamic understanding of our field.
An area of great interest to those researching flowback is the interaction of water and salt inside the shale reservoir. After a well is stimulated, the flowback fluids tend to show a rising concentration of salt that falls back to near zero over time. Most shale producers in North America have given little thought to the flowback stage following hydraulic fracturing. Others have come to realize it represents a valuable opportunity to learn more about their wells. On the far end of the flowback spectrum is a completion process called soakback.
When it came to decide where to collect a critical sample of fractured rock, a new method for turning microseismic data into a heat map designed to display the most intense fracturing activity was considered. Partitioning interwell tracer tests (PITTs) have been used to estimate remaining oil saturations (ROSs) during waterflooding. This paper reviews the design and implementation of a full-field interwell tracer program for a giant onshore oil field in Abu Dhabi. The surge in unconventional completions has created a substantial accumulation of previously hydraulically fractured wells that are candidates for hydraulic refracturing. Rising demand for flowback technologies to reduce uncertainties is leading to the creation of more hydrocarbon and water tracers.
Fields in the Upper Assam-Arakan Basin have been studied intensely to find prospective sweet spots, perforation intervals for new wells, and potential workover candidates. These forecasts, guided only by dynamic-numerical-model results, have had mixed results when implemented in the field. In this paper, an integrated work flow is proposed for brownfields where oil production is driven mainly by water injection. Produced-water salinity plays a key role, acting as a natural tracer and, thus, helping avoid additional costs for new data acquisition. Is Industry Ready for Brownfields’ Prime Time?
This paper introduces a new core-analysis work flow for determining resistivity index (RI), formation factor (FF), and other petrophysical properties directly from an as-received (AR) set of core samples. In this paper, the authors discuss the characterization process for GR tools and how they behave in boreholes different from the one used in the University of Houston (UH) GR characterization pit. This paper discusses a study undertaken to gain better understanding of nuclear magnetic resonance (NMR) characteristics of volcanic reservoirs with different lithologies. For this year’s feature, the selected papers provide innovative work flows that assist in determining productivity, reduce the effect of uncertainty conditions, and spark rejuvenation. Twelve organizations—universities and private technology companies—will conduct research and development on emerging shale plays and technologies covering everything from digital pressure-sensing to smart microchip proppant.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. In the context of injectors, tracers are chemicals placed in the flow stream of an injector to determine that the water takes from an injector to the producing wells.
In certain situations, it is necessary to obtain a reliable measurement for connate water saturation (Swc) in an oil reservoir. The single well chemical tracer (SWCT) method has been used successfully for this purpose. The SWCT method has been used successfully for this purpose in six reservoirs. The SWCT test for Swc usually is carried out on wells that are essentially 100% oil producers. The procedure is analogous to the SWCT method for Sor, taking into account that oil is the mobile phase and water is stationary in the pore space.