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Gamma ray (GR) logs from infill wells in heavy oil development projects frequently exceed 1000 GAPI, but only through the hot vapor cloud that develops as injected steam displaces heavy oil. GR values in the same sands that are liquid-filled, and immediately below the vapor-filled rock, are typically less than 100 GAPI. Previous work (O’Sullivan, 2008) shows that high GR values are caused by drilling-related cooling of vapor-filled rock. GR is thought to increase when water- and hydrocarbon-molecules, with solubilized radon atoms attached, are concentrated by 100 times or more as they approach the dew point and condense around a chilled well. After the chilled well begins to re-heat and equilibrate with the hot reservoir (36 hours or less) GR returns to normal levels. An experiment demonstrated that the cycle of GR increase and decrease can be repeated indefinitely, simply by chilling the well and then allowing it to warm back.
Samples of the condensed vapor have not been acquired, nor has condensed vapor gamma (“CVG”) been generated in a lab under controlled conditions, so much remains to be learned about the nature of CVG, and how it can be used to understand reservoir processes.
To put the condensed vapor gamma (CVG) effect into context, logs from thousands of heavy oil development wells from two large oil fields of the San Joaquin Valley, California were systematically reviewed. GR logs through vapor-filled rock for reservoirs in Midway-Sunset Field show that CVG amplitude is higher (≈ 2000 GAPI) in poorly-sorted rocks than in well-sorted clean sands (≈ 200 GAPI). The difference is driven by higher residual oil saturation in poorly-sorted rocks. Higher radon solubility and vapor pressure for oil, compared to water, lead to higher CVG values.
GR logs through well-sorted sands in Belridge Field, were anticipated to be low, and similar to those for well-sorted sands in Midway-Sunset Field. Instead, the CVG amplitude is unexpectedly high, exceeding 10,000 GAPI. A cross section of seven closely-spaced wells, drilled within an eight-year time span, shows that these very high GR values strongly correlate within a 60-foot interval. For the entire field, maps that track the year-by-year onset of high GR show interesting, but unexplained patterns that are restricted to limited areas and time intervals.
The difference between the CVG responses in the two fields may be explained by the observation that, for Belridge Field, the very high GR values occurred years after the steam flood on this reservoir peaked, during the time when development of a deeper reservoir containing light hydrocarbons was accelerating. CVG amplitude may have increased when the heavy oil vapor cloud was overprinted with light hydrocarbon from the deeper reservoir. With the light hydrocarbon, vapor pressure increases and improves the efficiency of radon absorption.
The observations suggest that, under certain conditions, it is possible to develop a method for in situ evaluation of vapor properties. Although the condensation-induced gamma signal has only been documented to occur in wells drilled in heavy oil steam floods, the effect could occur in any reservoir containing condensable vapor, provided that the vapor can be cooled to the dew point. Applications include evaluation of vapor composition, identification of barriers, and time-lapse monitoring of changes in vapor properties as an indicator of enhanced recovery process efficiency.
Controlled generation of CVG in the laboratory is a logical next step toward improved understanding of this phenomena. Continuous in situ observation and monitoring of CVG is also recommended, in order to explore the linkage between CVG and development activities.
Gamma-ray (GR) logs from infill wells in heavy-oil development projects frequently exceed 1,000 GAPI, but only through the hot vapor cloud that develops as injected steam displaces heavy oil. GR values in the same sands that are liquid-filled, and immediately below the vapor- filled rock, are typically less than 100 GAPI. Previous work showed that high GR values are caused by drilling-related cooling of vapor-filled rock. Gamma-ray values are thought to increase when water and hydrocarbon molecules approach the dewpoint and condense around a chilled well. As solubilized radon concentrates in these droplets, GR values can increase by ≥100x. After the chilled well begins to reheat and equilibrate with the hot reservoir (36 hours or less) GR values return to normal levels. An experiment demonstrated that the cycle of GR increase and decrease can be repeated indefinitely, simply by chilling the well and then allowing it to warm back.
To put the condensed vapor gamma (CVG) effect into context, logs from thousands of heavy-oil development wells from two large oil fields of the San Joaquin Valley, California, were systematically reviewed.
The observations suggest that it is possible to develop a method for in-situ evaluation of vapor properties. Although the condensation-induced gamma signal has only been documented to occur in wells drilled in heavy-oil steamfloods, the effect could occur in any reservoir containing condensable vapor, provided that the vapor can be cooled to the dewpoint.
Controlled generation of CVG in the laboratory is a logical next step toward improved understanding of this phenomenon. Continuous in-situ observation and monitoring of CVG is also recommended in order to explore the linkage between CVG and development activities.
Abstract In the Midway Sunset Oil Field in Central California, operators inject steam into the shallow diatomite formation to enhance heavy oil recovery through imbibition, wettability alteration, and viscosity reduction, among other mechanisms. The injected steam, however, does not always remain in the reservoir or return through the wells. In two zones in the study area, the steam comes out at the surface, creating sinkholes, seeps, and steam outlets (see Figure 1b and 1c). These phenomena, called "surface expressions," pose safety and environmental hazards. This study examines attributes of the zones with surface expressions that may contribute to their occurrence. It is hypothesized that the surface expressions are caused by leakage of steam through old improperly abandoned wells, high injection pressure, structurally controlled flow patterns, high injection volumes, or flow along naturally occurring faults, among other possible factors. Spatial statistical analysis using logistic regression and classification trees is used to explore the relationship between the surface expressions and spatial attributes. The results point to a significant spatial correlation between the surface expressions and two predictors: concentration of plugged wells and geologic seal thickness. These predictors emphasize the importance of both properly abandoning retired wells and having sufficient seal between the producing zone and the surface.
ABSTRACT The Midway Sunset oil field in the San Joaquin Valley of California is one of the United State's largest fields, having produced approximately three billion barrels of oil out of various reservoirs. Many of these reservoirs contain heavy oil, requiring recovery by steam to reduce the viscosity of the oil and allow it to flow. In steamflood operations, monitoring the steam's distribution and behavior is necessary for effective steam management and identification of bypassed oil. Cased-hole neutron logs are critical to this surveillance and are acquired throughout the life of the steamflood operation using cased observation wells. Each subsequent cased-hole neutron porosity is compared to the original open-hole neutron porosity to determine the increase in steam saturation and corresponding decrease in oil saturation that has taken place since the well was drilled. These logs are used to define current steam-oil contacts throughout the field, allowing reservoir teams to modify steam injection accordingly. There are many cased-hole neutron tools available, but they vary in tool characteristics, benefits and costs. Some tools can only be run in temperatures lower than 300 degrees Fahrenheit (degF), while steam chest temperatures can reach 350 degF or more. This constraint leaves fewer tool options for some wells, and the data from these tools has not always been reliable. To better define the quality, limits and value of this data, we test multiple hightemperature neutron tools, including both chemically sourced and electrically-sourced tools, by running them in a new well immediately after completion to compare them directly to the open-hole neutron log and to each other. We analyze the data quality, benefits and costs of the different tools and design a plan for our future surveillance. INTRODUCTION The Midway Sunset oil field is located in Kern County at the southern end of the San Joaquin Valley in central California (Figure 1). It is one of the United State's largest oil fields by total production, having yielded approximately three billion barrels of oil since the beginning of its development in the late 1890s (Miller, 2008). It has produced out of many different reservoirs that represent various depositional environments, from alluvial fans to deep-water turbidites. These reservoirs contain oil from less than 10 to greater than 30 API gravity, with the majority being heavy-oil reservoirs that currently require secondary recovery methods to access remaining reserves. The Potter and Webster are two such reservoirs.