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The experiments were operated for the cylindrical sample (cement/steel) in high temperature and high pressure (HTHP) CO2 environment to simulate surrounding CO2 attack in oil and gas well. The interfacial evolutions between well cement and casing steel were measured, including mechanical property, structure alteration, chemical change and electrochemical character. The interfacial behaviors are attributed to the competition of hydration and degradation of Portland cement. The damage at the interface was faster than the cement bulk deterioration by carbonation. Thus, the interface provided a potential flow leakage pathway for the HTHP gas and fluid in the well, so improving interfacial stability between well cement and casing steel is the key issue to long-term zonal isolation.

This paper proposed a semi-theoretical model to quantitatively predict leakage rate of tubing and casing premium connections. The geometric parameters of the sealing surface profile approximated by a sinusoidal micro-convex surface were first obtained based on the random normal distribution sampling method. With the actual area prediction formula for elastic–plastic contact of an axisymmetric sinusoidal micro-convex body based on the equivalent simulation principle, the circumferential leakage width and radial average leakage height of the micro-leakage channel between sealing surfaces were then acquired with the surface roughness and geometric mean contact pressure. At last, the actual micro-leakage rate of the premium connection was derived by considering the non-uniform contact pressure distribution between sealing surfaces. An example was investigated to validate the model and reveal the sealing and leakage characteristics, and anti-leakage measures were proposed. The results show that average contact pressure, circumferential leakage width, and radial average leakage height between sealing surfaces were non-uniformly distributed. The leakage rate of a premium connection decreases exponentially with an increase in radial interference between sealing surfaces. In order to reduce leakage rate, it is beneficial to increase radial interference and lower sealing surface roughness. [ABSTRACT FROM AUTHOR]

Aiming at the stress corrosion cracking behavior of a high strength steel, the air working conditions, the annulus protection fluid and the organic salts mud were simulated under the temperature of 60 °C, 100 °C, 150 °C by slow strain rate tests (SSRT). Tensile strength and elongation and stress corrosion cracking susceptibility index and fracture morphology were analyzed by stress–strain curves and SEM. To determine the applicability of high strength steel under different working conditions, the extent of damage were analyzed quantitatively. The results showed that less degree of stress corrosion occurs when temperature below 100 °C or even lower, and severe increase of stress corrosion occurs when temperature is 150 °C. The high strength steel stress corrosion cracking tendency increase as the temperature grows, and so do the stress corrosion cracking susceptibility index F(σ) and F(δ). Besides, the tendency of increase of F(σ) is more significant than that of the F(δ). In the working conditions of the organic salt mud, the changes of mechanical properties of the high strength casing steel are more significant. The corrosion pits on the sample surface contributed to such changes as a mainly factor. The crack nucleation can occur under the action of stress concentration at the bottom of the corrosion pits, and results in crack initiation extension inside the sample along the direction perpendicular to the tensile stress. In addition, the annulus protection fluid protected the strength and toughness of the casing excellently. [ABSTRACT FROM AUTHOR]

In this paper, the statistics of the size distribution of non-metallic inclusions in five drilling materials were performed. Based on the maximum non-metallic inclusion size, the fatigue strength of the drilling material was predicted. The sizes of non-metallic inclusions in drilling materials were observed to follow the inclusion size distribution rule. Then the maximum inclusion size in the fatigue specimens was deduced. According to the prediction equation of the maximum inclusion size and fatigue strength proposed by Murakami, fatigue strength of drilling materials was obtained. Moreover, fatigue strength was also measured through rotating bending tests. The predicted fatigue strength was significantly lower than the measured one. Therefore, according to the comparison results, the coefficients in the prediction equation were revised. The revised equation allowed the satisfactory prediction results of fatigue strength of drilling materials at the fatigue life of 10 rotations and could be used in the fast prediction of fatigue strength of drilling materials. [ABSTRACT FROM AUTHOR]

The corrosion of oil country tubular goods (OCTG) gets more and more serious especially in the acidic environment. So, it is very important to develop a perfect anticorrosion technology for exploring sour oil and gas fields economically and safely. Analysis indicates that the bimetal-pipe (BP) which consists of the base layer of low carbon steel and a corrosion resistant alloy (CRA) cladding layer is an economic and reliable anticorrosion technology and has broad application prospects in the transportation of acid medium. However, theoretical study of hydraulic expansion mechanism for BP is not enough. In this paper, the deformation compatibility condition of BP was obtained by studying the deformation rule of the (CRA) liner and the outer pipe of carbon steel in the forming process; the mechanical model which can compute the hydroforming pressure of BP has been established based on the nonlinear kinematic hardening characteristics of material; furthermore, based on the stress strain curve of inner pipe simultaneously, the calculation method of the plastic hardening stress has been proposed. Thus, the accurate method for computing the forming pressure was obtained. The experimental data show that results are consistent with results of the proposed model. It indicates that the model can be used to provide theoretical guidance for the design and production as well as use of BP. [ABSTRACT FROM AUTHOR]

In this paper, we analyze the potential factors affecting the hydrogen sulfide type of stress corrosion cracking in C110 casing pipes. In order to further study these cracking factors, the methods of material property testing, scanning electron microscopy, XRD, TEM, and 3D ultra-depth-of-field were applied in the experiments. Besides that, an HTHP autoclave was independently designed by the laboratory to simulate the actual corrosion environment, and the potential factors affecting the stress corrosion cracking of C110 casing pipes were determined. The test results showed that the chemical composition, metallographic structure, hardness, and non-metallic inclusions of the two types of C110 casing pipes were all qualified. In fact, there remains a risk of stress corrosion cracking when the two kinds of C110 casing pipes serve under long-term field-working conditions. It is considered in this paper that the precipitates on the material surface, stress damage, and pitting corrosion are all critical factors affecting the stress corrosion cracking of casing pipes. [ABSTRACT FROM AUTHOR]

The wellhead casing pressure (WHCP) resulted from gas production, downhole operations, casing and oil tubing or packing leakage poses great challenges to the mechanical integrity of cement sheath in HTHP gas wells. This paper proposed an analytical model of cement sheath on the basis of the multi-layer thick wall cylinder theory and Mohr–Coulomb failure criterion. The pressure and temperature loads were both considered in the model and the calculated stresses are all in good agreement with those obtained by FEA method. Meanwhile, the influences of the WHCP on cement sheath stress and integrity have been investigated with the proposed model, also a safety factor diagram of cement sheath at the weakest casing interface has been drawn by considering WHCP ranged from 10 to 70 MPa and wellbore temperature change ranged from −60 to 60 °C. Results show that the greater the WHCP, the lower the safety factor and the smaller the influence of wellbore temperature change on it. If the WHCP is less than 40 MPa, wellbore temperature effect cannot be ignored. For a specific gas well, the safety factor diagram can be used to determine the reasonable maximum allowable WHCP, which is of great guiding significance for protecting the cement sheath integrity and improving the WHCP management level in HTHP gas well. [ABSTRACT FROM AUTHOR]