In underground oil reservoirs, Hydrogen sulfide is usually found coexisting with the oil due to bacteria reduction over a long period of time. The amount of H2S in the oil varies from place to place around the globe. When the oil extraction process begins, the presence of Hydrogen sulfide becomes noticeable as drilling tools, piping and other equipment suffer from sulfide stress cracking, electrochemical corrosion and corrosion fatigue. For this reason, the oil industry invests millions of dollars per year trying to find better ways to reduce the amount of H2S in oil. An important part of the current investigations deals with brine (sea water)/oil mixtures. The reasons are two-fold: 1) one way of extracting the petroleum from the reservoir is by injecting brine into it and since it has a higher density than oil, the latter will be ejected up to the surface. Taking into account the complex fluid flow occurring within the reservoir it is easy to understand that some brine will also be present as part of the ejected fluid; 2) brine is already present in the reservoir, so independent of the extraction method used, there will be a brine/oil mixture in the ejected flow. When brine and oil have absorbed H2S under pressure in the reservoir and then suffer a decompression during the extraction process, a certain amount of H2S is released from the liquid phase. In order to have a better prediction of how much Hydrogen sulfide can be liberated a good understanding of H2S absorption by these liquids is necessary. The amount of gas a solvent absorbs is a function of pressure, original gas concentration and temperature as described by Henry's Law. The purpose of this thesis is to experimentally analyze how much of the corrosive gas is absorbed into different brine/oil mixtures, and brine and oil, separately. In order to find sufficient data for a thorough analysis, different reservoir simulation scenarios were created. The liquids were mixed from pure brine to pure oil, resulting in 33% and 66% water cuts. Data were obtained at 2 pressures of 20atm and 70atm at room temperature. H2S concentration was also a variable, changing the original gas concentration through different values: 50, 100, and 300ppm. These experiments were conducted in an autoclave system and will better explain the hydrostatic process that occurs inside the reservoir. It was found that throughout all the water cuts, the role that total pressure plays in the absorption phenomena is of less importance as the original H2S concentration is increased. In the same manner it was observed that the highest mass-absorption ratios are always found between 50 and 100ppm and the lowest at 300ppm, this is observed for all water cuts and total pressures. Another important finding was that the ability to absorb the corrosive gas decreases as the original H2S concentration increases and this proves to be true for all water cuts and system pressures. After conducting these different reservoir scenarios, tests were conducted to simulate 300m of the horizontal section of the pipe that connects the head of the well with the platform. This was done with a high pressure 300-meter long loop. It was found that the corrosive gas is absorbed at a higher rate when there is a flow, opposite to a hydrostatic case. Henry's Law constant was identified for each water cut and each pressure, however, the test procedure could not be validated since the gas being studied was not in its pure form. Understanding the absorption phenomena of Hydrogen sulfide in different water cuts will definitely be of great help to the oil industry to make better forecasts of H2S concentrations being ejected from each well.
| Identifer | oai:union.ndltd.org:ucf.edu/oai:stars.library.ucf.edu:etd-4435 |
| Date | 01 January 2008 |
| Creators | Zea, Luis |
| Publisher | STARS |
| Source Sets | University of Central Florida |
| Language | English |
| Detected Language | English |
| Type | text |
| Format | application/pdf |
| Source | Electronic Theses and Dissertations |
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