Successful acid stimulation programs are achieved when more near well-bore damage is removed than is induced by the acid treating fluid. Acid induced asphaltene sludging is becoming an increasing cause of oil well stimulation treatment failure. Laboratory tests on 231 crude oils from 17 formations in the U.S. and Canada, have been tested for sludge sensitivity.Numerous chemical processes involved in an acid system contribute to the effectof acid on sludge potential. Surface tension has been used in the past as a guideline for predicting the sludge potential of a chemical system. However, surface tension, in and of itself, is not a factor in acid induced sludge. In addition, this data indicates that as oilfields mature and are placed on secondary and tertiary recovery, sludge sensitivity increases. As a result of this data, a crude oil classification system is presented based on API gravity and asphaltene content. By classifying the crude oil, conclusions can be reached regarding sludging potential.This study addresses many such chemical options which include acid strength, acid type, solvent preflush, iron control and additive compatibility. The oxidation potential of iron contaminated acid is also clarified.
survey on over 300 wells in various locations.
The expanded use of sandstone matrix acidizing techniques may have been the most significant trend of the turbulent 1980's. Gulf Coast operators have found that remedial acid treatments cost a fraction of that required for a comparable offshore completion. Improved design and application techniques now provide economic success rates greater than 80% with most treatments paying out in less than 30 days. However, one area that continues to frustrate designers of acid treatments is the unpredictability of crude oil reservoirs. Current testing procedures are inadequate, failing to accurately replicate the interaction between the treating fluid and acid sensitive crudes. Reliance on these procedures can produce catastrophic facility upsets, downhole emulsion blocks, reduced damage removal efficiency or result in a marginal treatment response. A new simplified laboratory testing procedure was developed which more accurately simulates treatment effects under reservoir conditions. This laboratory test demonstrates the need for less reliance on surfactant non-emulsifiers and an expanded use of mutual solvents. Field data confirms more accurate prediction of add compatibility. In addition, acid treatments designed utilizing this laboratory procedure showed greater initial production response and maintained the incremental increase for a much longer time. Design guidelines are presented which address concerns of mutual solvent/corrosion inhibitor incompatibility, high temperature applications and treating volume requirements.
Most gravel packed completions are considered successful if the well produces sand free. However, many successfully gravel packed wells suffer reduced productivity as a result of formation damage induced by current gravel pack completion practices. Gravel packing even a slightly damaged formation can result in long term detrimental effects on production. The most predominate problem is that dehydration of the gravel carrier fluid will be restricted and perforation tunnels will not tightly pack.The areas of interest in which formation damage can be limited during a gravel pack completion include perforating, filtration, gravel carrier fluid selection, lost circulation control, and workstring hygiene. In addition, fluid leak-off during gravel packing may be optimized by proceeding the gravel pack slurry with low strength acid.
Laboratory tests were conducted to study the effects of using finely ground oil soluble resin as a diverting agent in hydrochloric-hydrofluoric acid treatments. The evaluation was conducted using a wellbore model which simulates varying permeability. These test results indicate that even though an even vertical distribution of fluids occurred when oil soluble resin was added continuously to all fluids, an inadequate ratio of HCl to HCl-HF acid was evident in the high permeability sections. This problem limits the effectiveness of a mixed acid system and may create acid induced inorganic precipitates. Based on results of the continuous diverting tests, a series of staged diverting evaluations were conducted. These results indicate that oil soluble resin may be effectively used in stages between acid stages to divert injected fluids.
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