Field Treatment To Stimulate A Deep, Sour, Tight Gas Well Using A New, Low Corrosive And Environmentally Friendly Fluid
- Theo Stanitzek (AkzoNobel) | Corine De Wolf (AkzoNobel) | Steffan Gerdes (Fangmann Energy Services) | Nils R. Lummer (Fangmann Energy Services) | Hisham A. Nasr-El-Din (Texas A&M University) | Alan K. Alex (AkzoNobel)
- Document ID
- Society of Petroleum Engineers
- SPE Kuwait International Petroleum Conference and Exhibition, 10-12 December, Kuwait City, Kuwait
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 1.6.9 Coring, Fishing, 5.8.1 Tight Gas, 3 Production and Well Operations, 4.3.1 Hydrates, 5.4.10 Microbial Methods, 5.8.7 Carbonate Reservoir, 3.2.4 Acidising, 4.3.4 Scale, 4.2.3 Materials and Corrosion, 5.2 Reservoir Fluid Dynamics, 2 Well completion, 4.1.5 Processing Equipment, 2.2.2 Perforating, 2.5.2 Fracturing Materials (Fluids, Proppant)
- sour wells, chelating agents, deep wells, CRA, matrix acidizing
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Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Hydrochloric acid is usually used for matrix acidizing or acid fracturing of carbonate wells. It simply dissolves the rock and creates wormholes when pumped at the optimum rate, thus by-passing the damaged zone and increasing well productivity. This procedure is not that simple in deep gas and/or oil wells because the bottomhole temperature is high. At high temperatures, the acid reacts vigorously with the rock, and the corrosion rate of well tubulars is high. This is especially true in wells completed with Cr-based alloys. In these cases, HCl dissolves the protective layer (Cr2O3) and can severely corrode well tubulars. The industry developed various techniques to overcome the shortcomings of HCl acids. For example, to reduce the reaction rate of the acid with the rock, polymers or viscoelastic surfactants were added to the acid to increase its viscosity, and thus reduces the reaction rate. Acid can be emulsified in diesel or xylene. The presence of a hydrocarbon external phase can significantly reduce acid reaction rate with the rock. To address the corrosive nature of HCl at high temperatures, a large volume of preflush of an aqueous solution can be used to reduce the bottomhole temperature of the treated well. One can also increase the loading of corrosion inhibitor and use intensifiers at temperatures greater than 200. Another option is to use weaker organic acids, e.g., acetic and formic acids. However, all of these solutions have limitations and serious drawbacks.
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