tracer test analysis

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.

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.

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. A low power radioactive isotope used to tag water or other fluid for tracing the path of fluid in the reservoir or in a well.

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.[1] 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.

In formations where the pore space is occupied by a stationary gas phase and a mobile water phase, such as in a watered-out gas reservoir, the residual gas saturation (Sgr) may need to be measured in situ. The Sgr also can be determined using a single-well injection/production test method.[1] Sgr measurement involves injecting and immediately producing a suitable volume of water. As the injected water enters the formation that contains residual gas, the water dissolves the gas, becoming saturated at the temperature and pressure in the reservoir. A region of increasing radius around the wellbore is stripped of gas.

Even with a properly designed single well chemical tracer (SWCT) test, interpreting the data requires judgment calls, and typically, simulation, to arrive at a final estimation of residual oil. Tomich et al.[1] report one of the earliest SWCT tests, which was performed on a Frio Sandstone reservoir on the Texas Gulf Coast. The results of this test are used here to demonstrate the details of SWCT test interpretation for an ideal situation. The test well in the Tomich et al.[1] report was in a fault block that had been depleted for several years. Because of the natural water drive and high permeability of the sand, the formation was believed to be near true Sor.

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. The following 19 pages are in this category, out of 19 total.

A passive tracer that labels gas or water in a well-to-well tracer test must fulfill the following criteria. It must have a very low detection limit, must be stable under reservoir conditions, must follow the phase that is being tagged and have a minimal partitioning into other phases, must have no adsorption to rock material, and must have minimal environmental consequences. The tracers discussed in the following sections have properties that make them suitable for application in well-to-well test in which dilution volumes are large. For small fields in which the requirement with respect to dilution is less important, other tracers can be applied. Figure 1.1 – Production curve of S14CN compared with the production curve of HTO in a dynamic flooding laboratory test (carbonate rock) (after Bjørnstad and Maggio[2]). There are no possibilities for thermal degradation, and it follows the water closely. The 36Cl- is a long-lived nuclide (3 105 years), and the detection method is atomic mass spectroscopy rather than radiation measurements. The disadvantage is that the analysis demands very sophisticated equipment and is relatively time consuming. For mono-valent anions, the retention factors (see Eq. 6.2) are in the range of 0 to -0.03, which means that such tracers pass faster through the reservoir rock than the water itself (represented by HTO). A compound such as 35SO42- may be applied in some very specific cases but should be avoided normally because of absorption. Some anionic tracers may show complex behavior. Radioactive iodine (125I- and 131I-) breaks through before water but has a substantially longer tail than HTO. Both a reversible sorption and ion exclusion seem to play a role here. Cationic tracers are, in general, not applicable; however, experiments have qualified 22Na as an applicable water tracer in highly saline (total dissolved solids concentration seawater salinity) waters. In such waters, the nonradioactive sodium will operate as a molecular carrier for the tracer molecule. Retention factor has been measured in the range of 0.07 (see Eq. 6.2) at reservoir conditions in carbonate rock (chalk). Wood[6] reported the use of 134Cs, 137Cs, 57Co, and 60Co cations as tracers.

The radioactive tracer-logging tool has a reservoir to hold radioactive material and a pump section at the top. For injection-well logging, two gamma ray detectors below the reservoir and pump are preferable. Some tools employ only one detector, but this is less desirable. The tool includes the circuitry to amplify and transmit the detector counts to the surface, for recording. Most natural radioactivity underground is from the decay of isotopes of potassium, thorium, and uranium.

The first SWCT test for Sor was run in the East Texas Field in 1968.[1] Patent rights were issued in 1971.[2] Since then, numerous oil companies have used the SWCT method.[3][4][5][6][7] More than 400 SWCT tests have been carried out, mainly to measure Sor after waterflooding. The SWCT method has gained considerable recognition over the past few years because of increasing interest in the quantitative measurement of Sor. Some experts[8][9] consider the SWCT test to be the method of choice because of its demonstrated accuracy and reasonable cost. A reliable in-situ measurement of Sor simultaneously defines the target for enhanced oil recovery (EOR) and allows estimation of the potential bypassed (mobile) oil in the field. This moveable oil is the target for infill drilling and/or flood sweep efficiency improvements.