China
Africa
Explore chapters and articles related to this topic
Fiber optics in the oil and gas industry
Published in P. Dakin John, G. W. Brown Robert, Handbook of Optoelectronics, 2017
When looking at the generic well structure all types of wells have a common setup: they all have a casing (see Figure 20.2), which is required to ensure that the borehole does not collapse, they all have a well head, which confines the access from the reservoir to the surface, and they also have a form of tubing, which reaches usually the reservoir section. For production wells, a packer is required to guarantee the isolation from the reservoir to the upper section of the well. The well head is seen as a second barrier, and it is standard to have two barriers in most counties to avoid integrity issues. The (production) tubing is a tube in which the hydrocarbon is produced up to the surface. All wells need a connection to the reservoir, that is, the hydrocarbon bearing layer; this is usually achieved by perforating, that is, shooting through the casing at the correct depth. This setup limits the placement of any sensor downhole; ultimately only two locations are available for sensing: along the tubing and along the casing (see Figure 20.2; blue and green indicate the fiber cable positions). Although one is closer to the environment one wants to monitor, the other allows much easier deployment of sensors. Also, at times there are legislative constraints on where to place the sensor. Without delving into the various production methods such as artificial lift [beam pumps, electrical submersible pump (ESP)], steam production (cyclic steam stimulation), or injection techniques (water, steam, and chemicals), the focus can now be shifted to the applications and their deployments.
Offshore Drilling and Completion
Published in Shashi Shekhar Prasad Singh, Jatin R. Agarwal, Nag Mani, Offshore Operations and Engineering, 2019
Shashi Shekhar Prasad Singh, Jatin R. Agarwal, Nag Mani
Production tubing forms the conduit for reservoir fluids to flow from wellbore to surface. In addition, it facilitates wellbore service operations such as wire line, stimulation, and circulation. Typically, tubing is run inside a casing or liner but can also be cemented in slim hole wells as the casing. Depending on the type of completion, one or two tubing strings may be used in the well.
Effects of Reservoir Souring on Materials Performance
Published in Torben Lund Skovhus, Dennis Enning, Jason S. Lee, Microbiologically Influenced Corrosion in the Upstream Oil and Gas Industry, 2017
David Fischer, Monica Canalizo-Hernandez, Amit Kumar
In addition to carbon and low-alloy steels, some CRAs used for downhole applications may also be susceptible to hydrogen embrittlement in mildly sour conditions. Stainless steels containing ferritic and martensitic microstructures tend to have higher susceptibility to SSC compared to stainless steels that are fully austenitic. A study on SSC of 13% Cr martensitic stainless steels (commonly used as production tubing in highly corrosive, sweet environments) showed cracking of a particular American Petroleum Institute (API) grade 13% Cr steel chemistry (having high carbon and low Ni) at PH2S = 1.0 kPa (0.15 psi) and pH ≤ 4 (Hara and Asahi 2000). In this case, hydrogen embrittlement was related to depassivation of the stainless steel and subsequent hydrogen ingress under the given pH conditions. Precipitation hardening (performed to increase material strength) of martensitic stainless steels greatly increases SSC susceptibility, especially if the alloy chemistry and heat treatment are not carefully controlled. A review of SSC testing on 17-4 PH, a martensitic stainless steel with Cu precipitation, under PH2S = 4.1 kPa (0.6 psi) showed failure of the material even at applied stress levels much lower than the material’s yield strength (Cassagne et al. 2003). While NACE MR0175 currently permits the use of 17-4 PH steel within H2S and pH limits of PH2S ≤ 3.4 kPa (0.5 psi) and pH ≥ 4.5, precautions still need to be taken to avoid the overstressing of these materials in mildly sour conditions.
Pressure survey, analysis and diagnostic of small diameter velocity string to improve well monitoring and surveillance
Published in Petroleum Science and Technology, 2023
Zhong Bo Zhai, Shi Wei Qi, Gayatri Kartoatmodjo
In October 2018, CO2 quasi-dry fracturing was carried out on the Shan12 reservoir (Haihua et al. 2021) at the depth of 3112.0 ∼ 3131.4m (MD) in Well Y9. After fracturing, a Ø88.9 mm (inner diameter of 74.2 mm) production tubing was used for flowback and well testing. The cumulative flow backed water is 106.3 m3, and the flowback ratio is 58.9%. The stable gas production rate is achieved with the 9 mm choke. The rate is 36.3 K m3/d for 12 hours, the stage water production is 0, and the average water production is 0 m3/d. This well was then put into production in April 2019. As shown in Figure 7, the gas rate (yellow histogram) continued to decline after the start of production before the VS was installed, the deliquification capacity was poor (light green histogram), and the gas well continued to face with water loading issue.
Exsolving two-phase flow in oil wells
Published in Geophysical & Astrophysical Fluid Dynamics, 2020
Victoria E. Pereira, Andrew C. Fowler
In this section, we introduce a two-fluid model for the isothermal exsolving upwelling flow in an oil well of length L and diameter d. The assumption of constant temperature is a reasonable simplification, as the temperature change along the well is relatively small (Ghorbani et al.2018 give an estimate for the temperature change of K). Inclusion of temperature would simply introduce a mild height dependence in the gas equation of state. For an oil well, we assume a one-dimensional domain as the production tubing is long and thin: the lengths are of the order of kilometres, and the diameter is typically 10 cm. We describe the one-dimensional flow by the spatial coordinate along the pipe axis z: z = 0 is the bottom of the pipe and z = L the top.
Corrosion-resistant alloy testing and selection for oil and gas production
Published in Corrosion Engineering, Science and Technology, 2018
Narasi Sridhar, Ramgopal Thodla, Feng Gui, Liu Cao, Andre Anderko
High pressure high temperature wells, typically defined as those where the bottom hole pressure exceeds 1000 bar (15,000 psi) and 177°C (350°F), pose many challenges to materials design from well testing to completion [1–9]. Because of well depths exceeding 1000 m, high-strength materials are required for production tubing, tubing hangers, and tubular connections. In addition to the high temperatures and pressures, these wells can also produce fluids containing high concentrations of chloride and high partial pressures of CO2 and H2S. Some reservoirs also contain elemental sulphur and other deleterious species, such as mercury. For these applications, high-strength low-alloy steels have not been found to be adequate, except as casing materials. Corrosion-resistant alloys (CRAs) are used in these applications because of their low general corrosion rates in the presence of high pressures of CO2 and H2S, and high temperatures. The term CRA is somewhat ambiguous because it does not refer to any inherent characteristics of a material, but its response to oil field environments relative to that of carbon steel [10]. CRA generally includes a wide range of Fe–Ni–Cr–Mo–W and Ti alloys that tend to form a passive film, but this review is limited to the former alloy class. The chemical compositions of various classes of Fe–Ni–Cr–Mo–W alloys are given in Table 1. A list of various CRAs is given, for example, in the International Standards Organization (ISO) 15156 standard (Part 3) [11]. Many of these alloys must be strengthened through cold working, heat treatments, or a combination of the two. These thermo-mechanical treatments may affect their performance [12–14].