No abstract

The fluid level software provides useful information to optimize oil and gas production when is required. The fluid level calculation is given by the acquisition of the half travel time of a soundwave and its acoustic velocity, which is highly influenced by changes in temperature, pressure, and specific gravity of gas, commonly seen in cyclic steam and nitrogen stimulations. Considering the above concept, a process for collection and statistical analysis of acoustic velocities was developed in a heavy oil field in order to ensure accuracy in fluid level detection in two specific groups of horizontal shallow wells whose gas composition was constantly altered by two different thermal EOR stimulations. The first group contains wells injected with cyclic steam, called EOR-1, and the second group includes wells injected with cyclic steam + nitrogen simultaneously, called EOR-2. Additionally, an estimation of the specific gravity of gas was calculated as a function of gas temperature and acoustic velocity collected, assuming an ideal mixture of gases at determined temperature ranges, considering the behavior of the casing pressure ​​as a constant (less than 2 Psig average). Scatter and box-plot were made using descriptive and inferential statistical methods for the study of data. With the analysis of the acoustic velocity of gas not only was possible to create a unique reference pattern with specific statistical Tukey's fences to improve the accuracy of liquid level detection by means of outlier determination, but it could also be interpreted the behavior of the annular gas composition in presence of additional gases such as water vapor and nitrogen at different annular gas temperature ranges during their whole production cycle, without requiring an expensive chromatographic analysis. In the same way, a detection method of nitrogen channeling between wells of the same producing sand could be established regardless of the EOR methodology performed, since it was determined that acoustic velocities from 1290 ft/s to 1400 ft/s are highly related to the presence of nitrogen in the gas composition being considered atypical in steam-injected wells (EOR-1), whose determined range varies from 1400 ft/s to 1520 ft/s.

This paper analyzes the use of a cyclic solvent injection technique (CSI) as a non-thermal EOR alternative to cyclic steam stimulation (CSS) for increasing the heavy oil recovery in a shallow reservoir located at the middle Magdalena basin in Colombia. A pilot well with less than 30% of water-cut and 10.9 °API was selected. Heavy natural gasoline of 30 °API obtained from the same reservoir was injected by using nitrogen (N2) as dispersing gas. Three procedures were performed being the procedure A, a Solvent slug injection of 60 bbl through the annular pushed and dispersed by 46,444 m3 (1,640 Mscf) of N2 immiscible (considering the low reservoir pressure). The procedure B consisted of injecting the same Solvent volume, but this time pushed by a third part of the N2 injected previously 15,481 m3 (547 Mscf). The procedure C consisted of only inject the same N2 volume than B procedure to analyze the heavy oil response without Solvent. There were collected production data, °API (by hydrometer), gas-flow and gas-gravity values using a liquid level software. Knowing the °API of each component in the laboratory—Solvent and heavy oil—the Solvent concentration from the real °API produced in production stages was calculated. All procedures had 48 hours of soaking, followed by a flowing process to tank to carefully release the excess of N2 before starting the production stage, avoiding gas lock issues. Without considering the Solvent injected, incremental oil production in procedure A was 232 bbl, in procedure B was 120 bbl and for procedure C, incremental oil only reached 11 bbl. With the last result it was determined the N2 injection by itself as a production mechanism without the Solvent effect in the in-situ heavy oil had a negligible effect on incremental oil. The gas-gravity showed the gas composition became heavier along the time, this considering the high-frequency N2 injections swept the methane near the well, requiring more time to produce the N2 traces from the porous media. The excess of N2 as a heavy Solvent dispersing mechanism does not warrant a better dilution effect since as observed in A and B procedures, Solvent concentration in the early production stage never dropped below 35% (17 °API), regardless of the N2 volume injected in the first two days. Finally, although A procedure had more incremental oil production (+93% than B), less N2 injected in B procedure was more efficient (+55% than A) regarding the incremental oil and N2 injected ratio (ONR).