A Story of Material Selection For Completion Tubing in HPHT Gas Fields in the Past 20 Years, Western China

2021 ◽  
Author(s):  
Xinxing He ◽  
Kelin Wang ◽  
Wei Fan ◽  
Hongtao Liu ◽  
Yan Long ◽  
...  
Keyword(s):  
Carbon Steel ◽  
Material Selection ◽  
Foreland Basin ◽  
Co2 Concentration ◽  
Dominant Factor ◽  
Reservoir Temperature ◽  
Gas Field ◽  
The Past ◽  
Kuqa Foreland Basin ◽  
Gas Fields

Abstract Kuqa foreland basin, which is located in the western of China, has the characteristics of HPHT with high CO2 partial pressure, and covered Yaha, Kela, Dina, Dabei, and Keshen gas fields. This story dated back to 2000 year that Yaha gas field was put into production, and the reservoir temperature 140°C, pressure 56 MPa, depth 4900-5300 m, and CO2 concentration 0.7-1.3 %. Carbon steel was selected for tubing material in the early stage of field development. After about 3 years, tubing perforation was caused by serious corrosion. Then carbon steel wasupgrade to 13Cr. However, it was found that there was serious corrosion in the connection part of tubing, and the corrosion was caused by the CO2 and condensate water. Based on the experience in Yaha gas field, the modified 13Cr tubing was used in the Dina2 gas fields, and the reservoir temperature 140C, pressure 110 MPa, depth 5200 m, and CO2 concentration 0.26-1.02 %. Although the well condition is less harsh, serious corrosion still occurred concentratedly on tubing pin end. Considering premium tubing leak in Dina field happened during acidification operations, and the results of series simulation tests conducted, the understandings were achieved that acid will cause serious corrosion to the inner wall of tubing, aslocal corrosion is dominant factor of stainless steel. The super 13Cr material was used in Keshen gas field which has reservoir temperature 150-188C, pressure 105-136 MPa, depth 6000-8038 m, and CO2 concentration 0.1-1.1 %. However, tubing fracture happened one by one, which originate from stress corrosion cracking caused by mixture of phosphate packer fluid and killing mud. Therefore, material selection needs to considerthe compatibility of different fluids, and formate was chosen as packer fluid. By December 2020,it has been used in 103 wells of Kuqa foreland basin, abnormal annular pressure is presented in 6 Wells, and the longest service time is six years. As the rapid exploration and development of Kuqa foreland basin, the proper material selection become more difficult for gas reservoir temperature more than 190C and its pressure greater than 140 MPa, the past practices about material selection may provide the reference, and the story about material selection will be continued.

Enhanced gas recovery, CO2 storage and implications from the CO2CRC Otway Project

2011 ◽  
Vol 51 (2) ◽  
pp. 684
Author(s):  
Peter Cook ◽  
Yildiray Cinar ◽  
Guy Allinson ◽  
Charles Jenkins ◽  
Sandeep Sharma ◽  
...  
Keyword(s):  
Pore Space ◽  
Co2 Storage ◽  
Co2 Concentration ◽  
Gas Production ◽  
Anthropogenic Sources ◽  
Future Price ◽  
Gas Field ◽  
Enhanced Gas Recovery ◽  
Gas Recovery ◽  
Gas Fields

Successful completion of the first stage of the CO2CRC Otway Project demonstrated safe and effective CO2 storage in the Naylor depleted gas field and confirmed our ability to model and monitor subsurface behaviour of CO2. It also provided information of potential relevance to CO2 enhanced gas recovery (EGR) and to opportunities for CO2 storage in depleted gas fields. Given the high CO2 concentration of many gas fields in the region, it is important to consider opportunities for integrating gas production, CO2 storage in depleted gas fields, and CO2-EGR optimisation within a production schedule. The use of CO2-EGR may provide benefits through the recovery of additional gas resources and a financial offset to the cost of geological storage of CO2 from gas processing or other anthropogenic sources, given a future price on carbon. Globally, proven conventional gas reserves are 185 trillion m3 (BP Statistical Review, 2009). Using these figures and Otway results, a replacement efficiency of 60 % (% of pore space available for CO2 storage following gas production) indicates a global potential storage capacity—in already depleted plus reserves—of approximately 750 Gigatonnes of CO2. While much of this may not be accessible for technical or economic reasons, it is equivalent to more than 60 years of total global stationary emissions. This suggests that not only gas—as a lower carbon fuel—but also depleted gas fields, have a major role to play in decreasing CO2 emissions worldwide.

scholarly journals Palaeo-fluid evidence of the multi-stage hydrocarbon charges in Kela-2 gas field, Kuqa foreland basin, Tarim Basin

2012 ◽  
Vol 39 (5) ◽  
pp. 574-582 ◽  
Author(s):  
Xuesong LU ◽  
Keyu LIU ◽  
Qinggong ZHUO ◽  
Mengjun ZHAO ◽  
Shaobo LIU ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Foreland Basin ◽  
Gas Field ◽  
Multi Stage ◽  
Kuqa Foreland Basin

Investigation on Material Selection in Missan Oilfields Similar Environment

2014 ◽  
Vol 641-642 ◽  
pp. 427-433
Author(s):  
Shuang Cheng ◽  
Feng Lin ◽  
Pei Long Yang ◽  
Pei Ke Zhu ◽  
Jin Gen Deng ◽  
...  
Keyword(s):  
Stainless Steel ◽  
Carbon Steel ◽  
Nickel Alloy ◽  
Martensitic Stainless Steel ◽  
Material Selection ◽  
Pressure Ratio ◽  
Service Condition ◽  
Corrosion Mechanism ◽  
Test Results ◽  
Chrome Steel

This paper analyzed the corrosion environment of Missan oilfields and investigated the oilfield country tubular goods used in other similar oilfields. Summarized the effect of partial pressure ratio of H2S/CO2 and Cl-to the corrosion behavior of OCTG. This paper concluded the service condition, test results and anti-corrosion mechanism of carbon steel, low-chrome steel, modified martensitic stainless steel and nickel alloy. Finally arrived at conclusion that the nickel alloy can meet the requirement of Missan oilfields, some literature reported that the modified martensitic stainless steel can apply in H2S/CO2 environment. In the condition that be easy to replace the tubular, carbon steel and low-chrome steel tubular can meet the requirement with corrosion inhibitor.

Experimental Research on Erosion of P110 Tubing during Perforating

2014 ◽  
Vol 1073-1076 ◽  
pp. 2244-2247
Author(s):  
Hu Sun ◽  
Zhi Jun Ning ◽  
Zu Wen Wang ◽  
Zhen Li ◽  
Zhi Guo Wang
Keyword(s):  
Weight Loss ◽  
Erosion Rate ◽  
Large Scale ◽  
Guar Gum ◽  
Electrochemical Corrosion ◽  
Low Velocity ◽  
Gas Field ◽  
Weight Loss Method ◽  
Loss Method ◽  
Gas Fields

Erosion is a main failure of tubings and downhole tools in Changqing gas field. It is necessary to evaluate the erosion rate for the safety of tubing and strings. In this paper, the erosion of P110 steel, in the 0.2%wt guar gum fracturing fluid which contains sands, is investigated by weight loss method in the self-made jet experiment device. It is indicated that the erosion rate increases with the increment of slurry velocity exponentially. When the slurry velocity is in low velocity area, the electrochemical corrosion of dissolved oxygen dominates in erosion mechanism; when slurry velocity increases into middle velocity area, the weight loss is controlled by the synergism of corrosion-erosion; and when the slurry velocity increases into high velocity area, the weight loss rate is dominantly depended on erosion of particles. The results can provide guidelines for large-scale fracturing work of Changqing gas fields.

Limitations of Corrosion Resistant Alloy in High CO2 Gas Production Systems: A Case Study

2021 ◽  
Author(s):  
Jorge Rodriguez ◽  
Susana Gómez ◽  
Ngoc Tran Dinh ◽  
Giovanni Ortuño ◽  
Narendra Borole
Keyword(s):  
Heat Transfer ◽  
Fluid Dynamics ◽  
High Pressure ◽  
Stainless Steel ◽  
Carbon Steel ◽  
Material Selection ◽  
Dynamic Modelling ◽  
General Corrosion ◽  
High Co2

Abstract The paper presents the application of a holistic approach to corrosion prediction that overcomes classical pitfalls in corrosion testing and modelling at high pressure, high temperature and high CO2 conditions. Thermodynamic modelling of field and lab conditions allows for more accurate predictions by a novel CO2/H2S general corrosion model validated by laboratory tests. In the proposed workflow, autoclave tests at high pressure and temperature are designed after modeling corrosion in a rigorous thermodynamic framework including fluid-dynamic modelling; the modeled steps include preparation, gas loading and heating of fluid samples at high CO2 concentration, and high flow velocities. An autoclave setup is proposed and validated to simultaneously test different conditions. Corrosion rates are extrapolated to compute service life of the materials and guide material selection. The results from the model and tests extend the application of selected stainless steel grade beyond the threshold conditions calculated by simplistic models and guidelines. Consideration of fugacities and true aqueous compositions allows for accurate thermodynamic representation of field conditions. Computation by rigorous fluid dynamics of shear stress, multiphase flow and heat transfer effects inside completion geometry lead to a proper interpretation of corrosion mechanisms and models to apply. In the case study used to showcase the workflow, conventional stainless steel is validated for most of the tubing. It is observed that some sections of the system in static condition are not exposed to liquid water, allowing for safe use of carbon steel, while as for other critical parts, more noble materials are deemed necessary. Harsh environments pose a challenge to the application of conventional steel materials. The workflow applied to the case study allows accurate representation and application of materials in its application limit region, allowing for safe use of carbon steel or less noble stainless steels in those areas of the completion where corrosion is limited by multiphase fluid-dynamics, heat transfer or the both. The approximation is validated for real case study under high CO2 content, and is considered also valid in the transportation of higher amounts of CO2, for example, in CCUS activities.

Advantages in Environmental Compliance For Maritime Corrosion Control

2015 ◽  
Author(s):  
Eric Lethe
Keyword(s):  
Material Selection ◽  
Shop Floor ◽  
Chief Financial Officer ◽  
Successful Implementation ◽  
The Past ◽  
New Methods ◽  
Traditional Procedure ◽  
Environmentally Sound ◽  
A Company ◽  
Selection Of

The need for environmentally compliant processes and materials in the Painting Industry grows more pressing every day. As the need for these processes grows, so grows the confusion regarding the selection and implementation of these new methods and materials. In the past, price and traditional procedure were the only criteria by which a material was procured. Speed and compliance with Original Equipment Manufacturer specification governed how things were done on the shop floor. With the advent of the environmental regulations, processes are being examined all across the globe. In many of the larger companies, the chief environmental officer has as important a role as the comptroller or Chief Financial Officer. Environmental managers are often not chemists or line painters, and typically, the environmental manager is skilled only in the policies of waste disposal, spill clean up, or remediation. The methods whereby a company can minimize the generation of hazardous waste remain less familiar. Often the examination of possible alternate techniques and materials are left for the last minute, or are conducted by personnel who are unfamiliar with how to make changes work. This is usually a recipe for failure in the implementing of anything new. This paper will suggest methods for selection of alternative products and processes in a clear and organized manner. Salient discussion points will be: 1. Process Examination 2. Material Selection 3. Steps For Successful Implementation 4. Possible Impediments 5. How to Avoid Risky Alternatives It will focus on procedures that will assist in the decision making process, and hopefully be of use in the choosing of environmentally sound equipment, chemicals, and methodologies.

Data-driven modeling decadal-to-centennial ENSO variability and its response to external forcing

2021 ◽  
Author(s):  
Aleksei Seleznev ◽  
Dmitry Mukhin ◽  
Andrey Gavrilov ◽  
Alexander Feigin
Keyword(s):  
Co2 Concentration ◽  
Data Driven ◽  
Time Interval ◽  
Solar Forcing ◽  
Russian Science ◽  
Dynamical Mechanism ◽  
Enso Variability ◽  
The Past ◽  
Sst Variability ◽  
Data Driven Modeling

<p>We investigate the decadal-to-centennial ENSO variability based on nonlinear data-driven stochastic modeling. We construct data-driven model of yearly Niño-3.4 indices reconstructed from paleoclimate proxies based on three different sea-surface temperature (SST) databases at the time interval from 1150 to 1995 [1]. The data-driven model is forced by the solar activity and CO2 concentration signals. We find the persistent antiphasing relationship between the solar forcing and Niño-3.4 SST on the bicentennial time scale. The dynamical mechanism of such a response is discussed.</p><p>The work was supported by the Russian Science Foundation (Grant No. 20-62-46056)</p><p>1. Emile-Geay, J., Cobb, K. M., Mann, M. E., & Wittenberg, A. T. (2013). Estimating Central Equatorial Pacific SST Variability over the Past Millennium. Part II: Reconstructions and Implications, Journal of Climate, 26(7), 2329-2352.</p>

Pseudo Dry Gas Technology: Pathway to Decarbonisation of Energy Consumption for Remote Offshore Gas Fields

2021 ◽  
Author(s):  
Tran Nguyet Ngo ◽  
Lee Thomas ◽  
Kavitha Raghavendra ◽  
Terry Wood
Keyword(s):  
Energy Consumption ◽  
Energy Transition ◽  
High Energy ◽  
Innovative Technology ◽  
Flow Loop ◽  
Gas Field ◽  
Power Requirement ◽  
Order Of Magnitude ◽  
Gas Fields ◽  
Technology Pathway

Abstract Transporting large volumes of gas over long distances from further and deeper waters remains a significant challenge in making remote offshore gas field developments technologically and economically viable. The conventional development options include subsea compression, floating topside with topside compression and pipeline tie-back to shore, or floating liquefied natural gas vessels. However, these options are CAPEX and OPEX intensive and require high energy consumption. Demand for a lower emission solution is increasingly seen as the growing trend of global energy transition. Pseudo Dry Gas (PDG) technology is being developed by Intecsea, Worley Group and The Oil & Gas Technology Centre (Aberdeen) and tested in collaboration with Cranfield University. This is applied to develop stranded or remote gas reserves by removing fluids at the earliest point of accumulation at multiple locations, resulting in near dry gas performance. This technology aims to solve liquid management issues and subsequently allows for energy efficient transportation of the subsea gas enabling dramatic reductions in emissions. The PDG prototype tested using the Flow Loop facilities at Cranfield University has demonstrated the concept’s feasibility. Due to a greater amount of gas recovered with a much lower power requirement, the CO2 emissions per ton of gas produced via the PDG concept is by an order of magnitude lower than conventional methods. This study showed a reduction of 65% to 80% against standard and alternative near future development options. The paper considers innovative technology and a value proposition for the Pseudo Dry Gas concept based on a benchmarked study of a remote offshore gas field. The basin was located in 2000m of water depth, with a 200km long subsea tie-back. To date the longest tieback studied was 350km. It focused on energy consumption and carbon emission aspects. The conclusion is that decarbonisation of energy consumption is technically possible and can be deployed subsea to help meet this future challenge and push the envelope of subsea gas tie-backs.

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