Casing damage is a complex process involving many natural and human factors such as geology, in-situ stresses, casing hardware, drilling/completion practices, reservoir production/stimulation designs. Chemical corrosion to the casing has been a consistent challenge to the industry starting from the very beginning of the petroleum industry which put steel casings underground. This paper describes a case study about casing damage caused by CO2 corrosion. Well data including geology, well casing/completion program, and production and injection history were first compiled. Analysis of the field data helped hypothesize about possible CO2 corrosion as the causal mechanism. Lab tests were thus devised to confirm if the casing steel is susceptible to the corrosion and to determine the corrosion rate. The preliminary test results demonstrated that the steel suffered from either general corrosion or localized cracking depending on the type of testing fluids, the degree of CO2 saturation in the test fluids, and the testing temperature. Mechanisms governing the various formsof corrosion damages observed will be discussed. The field data, lab test design and results to be presented in this paper will further enrich the industrial knowledge base in preventing the chemical corrosion from damaging the casing.
Casing damage is a complex process involving many natural and human factors such as geology, in-situ stresses, casing hardware, drilling/completion practices, reservoir production/stimulation designs. Chemical corrosion to the casing has been a consistent challenge to the industry starting from the very beginning of the petroleum industry which put steel casings underground.
The investigation reported here was initiated in an attempt to understand casing failure mechanisms experienced in NiuZhuang field, Shengli Oilfield, China. In 5 of the 6 wells investigated (N25–25, 25–53, N23–1, N23–46, N6), casing leaks or ruptures all happened shortly above the cement return height, 500–1400 m above the perforation interval or the reservoir payzone. Figure 1 shows the spatial correlation between the casing leak/rupture, cement return height, perforation interval and well target depth (TD). Except well N6 whose casing leaks happened 29 years after its completion, all other wells experienced the leaks 9 to 15 years after they were completed. The casing failure was first suspected by sudden occurrence of excessive water production contained in oil fluids. The casing leak sites were then identified via pressure testing of the casing. The field data did not show significant casing deformation around these leak/rupture sites. Workover tools or production tubing moved freely across these casing failure intervals. Therefore, it was hypothesized that casing failures at these wells were caused by chemical corrosion. Lab tests on the chemical corrosion were then designed to determine corrosion susceptibility and mechanisms of the casing steel used in the field. This paper summarizes some preliminary results obtained so far.
The casing tubing was sectioned and machined into flat coupons with a dimension of 1.377mm ‾10 mm ‾15mm for corrosion exposure. Table 1 lists water samples collected from the field. These samples were only occasionally observed to contain SO42-, therefore, the corrosion occurring on the casing tubing should be related to sweet corrosion/CO2 corrosion.
