Monitoring Reservoir Floods Using Oil and Water Geochemistry
Optimizing performance from a water, steam, or gas flood depends on identifying uneven progression of the flood front through the reservoir.
Injectant may move more rapidly through some parts of a reservoir than others, creating an uneven flood front. Such preferential movement of injectant through parts of the reservoir may result in premature breakthrough of the injectant at some producer wells. Uneven breakthrough can cause the loss or "orphaning" of oil in bypassed sections of the reservoir, and therefore can reduce ultimate oil recovery. Frequently, from data on progression of a flood, injection rates can be modified in certain areas so as to maintain an even flood front.
Oil geochemistry provides an inexpensive means for monitoring the progression of a flood.
In the case of steam or water floods of heavy oil accumulations, changes in the composition of produced oil over time can be used to identify the portions of the reservoir being impacted by the flood, and to estimate the relative production from discrete reservoir intervals (McCaffrey et al., 1996).
In the case of a gas flood, compositional data for (i) the injectant, (ii) the solution gas, and (iii) the produced gas can be used in combination to assess the percentage of injected gas present in produced gas.
Water geochemistry also provides a means for monitoring the progression of the flood front.
If injected water and formation water have different chemistries, then variations in produced water chemistry can identify portions of the reservoir being impacted by the flood (Okoro et al., 2000).
Please also see other information on water geochemistry here
Minimizing formation damage caused by interaction of the injectant with reservoir fluids and rock.
During either a miscible CO2 or hydrocarbon gas flood, dissolution of injected gas into the oil may reduce the solubility of asphaltenes and/or high-molecular-weight paraffins in the oil, resulting in precipitation of these components in the reservoir. By clogging pore throats, these organic precipitates may reduce injectivity, adversely affecting the producibility of the reservoir. This type of formation damage can be avoided by conducting core flood experiments in the laboratory that assess the affect of the injectant on the reservoired oil. If such experiments identify significant risk for formation of organic precipitates, then additional experiments can identify chemical modifiers that can be added to the injectant to prevent formation of organic precipitates by increasing the solubility of asphaltenes and/or high-molecular-weight paraffins in the oil/gas solution (Hwang et al., 1999).
During a waterflood, the injectant may react with reservoir minerals and/or with reservoir brine and cause precipitation of secondary minerals or swelling of clays that clog pore throats, reducing injectivity. This type of formation damage can also be predicted by considering in combination the compositions of the injected water, the reservoir brine, and the reservoir mineralogy.
For more information on the techniques described here, or to discuss a specific project, e-mail us at email@example.com, or call us at U.S. (214) 584-9169.
Hwang, R. J. and Ortiz J. (1999). Mitigation of asphaltics deposition during CO2 flood. Abstracts 19th International Meeting on Organic Geochemistry, Istanbul, Turkey, Tubitak Marmara Research Center Earth Sciences Research Institute. Vol. II: 601-602.
Okoro I.C., E. N. Olaniyan, J.O. Umurhohwo, B. A. Patterson, and D. D. Kennedy, 2000, Potential Uses of Injected Sea Water as a Tracer in Water Flood Management (abstract): Pennwell et al. ed., Offshore West Africa Conference, (Abidjan, Cote D'Ivoire, 3/21-3/23/2000).
McCaffrey M. A., Legarre H. A. and Johnson S. J. (1996). Using biomarkers to improve heavy oil reservoir management: An example from the Cymric field, Kern County, California. American Association of Petroleum Geologists Bulletin 80(6), 904-919.