Challenges During Shallow and Deep Carbonate Resevoirs Stimulation

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Abstract Carbonate reservoir stimulation has been carried out for years using HCl or HCl-based fluids. High HCl concentration should not be used when the well completion has Cr-based alloy in which the protective layer is chrome oxide which is very soluble in HCl. HCl or its based fluids are not recommended either in shallow reservoirs where the fracture pressure is low (face dissolution) or in deep reservoirs where it will cause severe corrosion problems. Different chelating agents have been proposed to be used as alternatives to HCl in the cases that HCl cannot be used. Chelating agents such as HEDTA (hydroxyethylenediaminetriaceticacid), and GLDA (glutamic -N,N-diacetic acid) have been used to stimulate carbonate cores. The benefits of chelating agents over HCl are the low reaction, low leak off rate, and corrosion rates. In this study, the different equations and parameters that can be used in matrix acid treatment were summarized to scale up the laboratory conditions. The conditions where HCl or chelating agents can be used were determined. The leak off rate was determined using the data from coreflood experiments and CT scans. Indiana limestone cores of average permeability of 1 md and core lengths of 6 and 20 in. were used. Chelating agents will be used at pH value of 4 and 0.6M concentration and compare that with the 15 wt% HCl. The experimental results showed that HCl has high leak off rate and caused face dissolution at low injection rate. The model to scale up the linear coreflood results to radial field conditions was developed and can be used to design for the optimum conditions for matrix acid treatments. Chelating agents can be used to stimulate shallow reservoirs in which HCl may cause face dissolution because it can penetrate deep with less volume or can be used in deep reservoirs where HCl may cause severe corrosion to the well tubular. Introduction One of the main problems encountered during the stimulation of carbonate reservoirs by HCl is the asphaltene precipitation. Asphaltic sludge can be formed when the crude oil is contacted by acid, the asphatene will aggregate and precipitate from the crude oil when their micelles are depeptized by chemical or mechanical means. HCl is a strong acid and it destabilizes the micelles causing the formation of sludge (Jacobs 1989). Sludge precipitation was found to be a strong function of acid concentration and it decreased with the use of weaker acids such as acetic, and formic acids. Another problem during carbonate acidizing using HCl is the precipitation of ferric hydroxide, and it was found that ferric ions contributed to large extent on the sludge precipitation. The formation of asphaltic sludge can lead to partial or complete plugging of the formation after acidizing treatment. It is extremely difficult to remove this damage from the formation, while it can be removed from the tubing and casings by aromatic solvents (Jacobs and Thorne 1986). Many additives are required to minimize the precipitation of asphaltic sludge such as corrosion inhibitors (to prevent more production of ferric ions), antisludge agents, and iron control agents to keep iron in solution. The solution to all these problems is to use less corrosive stimulation fluid, not strong like HCl (less H+), does not produce sludge when contacted with oil. All these features are present in the stimulation fluid that we are introducing this paper which is GLDA chelating agents. Matrix acid treatments usually require low injection rates to prevent fracturing the formation, but the problem of low injection rate is the rapid acid spending in the formation face if HCl acid was used. The rapid acid appending at the formation face limits the acid penetration inside the formation to bypass the damaged zone and create wormholes to create negative skin. The injection of HCl at low injection rates results in face dissolution, or complete dissolution to the matrix near the wellbore. The rapid acid spending consumes large acid volume without enhancement in the formation permeability (Fredd and Fogler 1997).