最近CO ₂碳捕获和封存(CCS) 项目的发展激增，引起了人们对美国环境保护署(EPA) 许可的注入井耐腐蚀性要求的关注。

在某些情况下，各种冶金技术在提高采收率 (EOR) 井中的长期成功历史被认为足以让 CCS 注入井实现相同的完井。缺乏有关这些合金在 EOR 井中的长期性能的实际数据，再加上对 VI 级井的更严格要求，表明情况并非如此。

介绍

_{最近，政府对包括CCS和CCUS在内的各种绿色举措提供了大量激励措施，引发了钻探和完井CO 2}注入井的热潮。然而，在这些井中做出明智的耐腐蚀性选择所需的腐蚀数据最多是最少的。_{一些石油和天然气专业人士认为，40 多年的 CO 2} EOR 石油经验与计划的 CCS 井没有区别。

这种比较不是有效的，并且考虑到监管机构要求长期遏制 CO _{2的需要，这种比较可能存在风险。}本文对注井冶金中CO _{2 EOR 和 CCS 进行了比较，并解释了该比较无效的原因。}

背景和比较

_{CO 2} EOR 在石油生产中有 50 年的成功历史，人们达成了共识，但基本上没有任何优点：注入井设备的腐蚀是可控的，不会导致某些部件（例如套管）的长期退化。 。

将这一经验应用于CO ₂ CCS 井几乎没有价值或没有价值的原因是缺乏关于EOR 井中套管的长期耐腐蚀性的具体数据。相反，该行业通常只是简单地用水泥堵塞这些井，并且在大多数情况下，在废弃之前不会检查套管。此外，在废弃多年后，工业界很少回来检查它们。

在少数情况下，对水泥岩心和套管进行了测井和回收，并进行了分析。例如，对 SACROC 油田暴露于 CO ₂超过 30 年的水泥和套管进行的分析显示，沿套管-水泥界面发生了腐蚀（Carey 等人，2007 年）。劳姆等人。(2016)根据多年来的一系列测井报告，Weyburn 油田的 CO ₂ EOR 井出现了严重的套管腐蚀。科普洛斯等人。(2007)提供了许多 CO ₂ EOR 井的调查数据，发现 11.1% 的井未通过机械完整性测试，并得出结论，由于 CO 2 对井下的腐蚀性，注入井机械完整性是 CO 2 注入和储存_的一个_问题。材料。

_{这两种CO 2}注入方法之间也存在许多显着不同的因素。其一，EOR 井通常比 CCS 井浅，因此温度和压力通常低于 CCS 井。此外，阵型往往独特不同。在 EOR 的情况下，地层通常是部分枯竭的油藏，其中含有一定量的石油，可以缓和腐蚀性。就 CCS 而言，地层通常是高盐度的非饮用水含水层。

_{EOR 和CCS 井之间的另一个重要区别是，历史上EOR 的CO 2}来源来自天然气工厂，其杂质很少，例如通常为H ₂ S 或偶尔含有少量硫醇。另一方面，CCS注入液流可能含有大量杂质，具体取决于CO ₂的来源，这可能对井下设备的腐蚀产生重大影响。这些杂质在 EOR 中很少见。

EOR 和 CCS 井之间的另一个重要区别是许可要求。在大多数情况下，EOR 井属于 EPA II 级井，而 CCS 和 CCUS 则需要符合 EPA VI 级要求。

EPA 对 VI 级井的要求是：

“确保为所有井组件计划的材料与计划的注入液和可能遇到的地层流体兼容，并且它们能够在项目期间抵抗腐蚀。”

40 CFR Part 146 Subpart H 中针对 VI 类井的类似语言也包含在内。

“所有井材料必须与材料可能接触的流体相容”

首先，碳钢套管在任何情况下都不能被认为耐腐蚀，其次，许多CCS井的设计寿命可以达到30年甚至更长。具体来说，EPA 要求注射后 50 年内进行注射后部位护理。

对于 II 类井的套管、油管、封隔器等没有此类要求。

在任何情况下碳钢管都不能具有耐腐蚀性；_{因此，对于暴露于与CO 2}接触的储层流体的部件，必须考虑使用耐腐蚀合金(CRA) 。为特定井环境选择合适的 CRA 是一个复杂的过程，如其他地方详述（Craig、Rowe 和 Doll 等人，2023）。

此外，对于 VI 类井，但对于 II 类和 EOR 井不需要：

“VI 类规则要求 VI 类许可证申请人为其项目制定并实施全面的测试和监测计划，包括注入物监测、井管腐蚀监测等。”

类似的语言再次体现在 CFR 中。要求根据 VI 级许可使用腐蚀试样或腐蚀环进行腐蚀监测，并测量质量损失和厚度损失。

该要求隐含地假设试样是由碳钢制成的，但在注射区使用 CRA 的情况并非如此。总的来说，CRA 在这些 CO ₂注入流中不会遭受质量损失或变薄。相反，如果它们容易受到腐蚀，则会采取点蚀或缝隙腐蚀的形式，而在许多情况下，在试样上不会观察到这种情况。

结论

由于目前还没有关于 CCS 井中套管和油管可接受的腐蚀损坏的标准或指南，并且由于 VI 级井需要在项目持续时间内抵抗腐蚀，因此当水存在时这些组件的唯一选择预计 CRA 将会出席。

供进一步阅读

J. William Carey 等人对来自美国西德克萨斯州 SACROC 装置的暴露于 CO2 30 年的油井水泥进行了分析和性能分析。国际温室气体控制杂志（2007 年）。

CO2 EOR 和封存的井眼腐蚀和故障评估： J. Laumb 等人在 Weyburn 油田的两个案例研究。等人。国际温室气体控制杂志（2016）。

J. Koplos 等人对注水井机械完整性的回顾 。等人。IEA 温室气体研发计划第三次井筒完整性网络会议，3 月 12 日至 13 日，新墨西哥州圣达菲（2007 年）。

B. Craig、A. Rowe、M. Warmack 等人编写的CCS 和 CCUS 注入井耐腐蚀合金选择指南。国际温室气体控制杂志（2023）。

J. Meyer 的二氧化碳提高采收率注入井技术总结 。API（2007）。

二氧化碳提高石油采收率。NETL（2010）。

CO2 混相驱提高石油采收率 作者：A. El-hoshoudy 和 S. Desouky。IntechOpen (2018)。

Bruce Craig是科罗拉多州丹佛市 MetCorr 的 SPE 成员和冶金和腐蚀领域的主题专家。他拥有科罗拉多矿业学院冶金工程学士、硕士和博士学位。40多年来，克雷格一直参与世界各地石油和天然气项目冶金设施的选择，包括墨西哥湾莫比尔湾（浅水）、墨西哥湾深水、落基山脉、亚洲、和中东。此外，他最近还参与了 CCS 和 CCUS 注入井的冶金选择。

Adam Rowe是休斯顿应力工程服务公司的 SPE 成员和首席冶金工程师。他拥有科罗拉多矿业学院冶金和材料工程学士和硕士学位。Rowe 在材料评估、腐蚀评估、焊接冶金、增材制造和冶金失效分析方面拥有专业知识。他曾参与多个不同行业的各种项目，最近的项目经验包括解决 CCS、储氢和海上风电开发中的制造、制造和腐蚀问题。

The recent surge in development of CO₂ carbon capture and storage (CCS) projects has brought focus on the requirements for corrosion resistance in the injection wells as required by US Environmental Protection Agency (EPA) permitting.

In some cases, the long successful history of various metallurgies in enhanced oil recovery (EOR) wells has been cited as sufficient to allow the same completions for CCS injection wells. The lack of actual data on the long-term performance of these alloys in EOR wells in combination with the more stringent requirements for Class VI wells suggests otherwise.

Introduction

The recent significant influx of large amounts of government incentives for a variety of green initiatives including CCS and CCUS has created a rush to drill and complete CO₂ injection wells. However, the necessary corrosion data to make informed choices for corrosion resistance in these wells is minimal at best. Some oil and gas professionals have argued that there is no difference between the more than 40 years of petroleum experience with CO₂ EOR and planned CCS wells.

This comparison is not a valid one and can be risky considering the need for very long-term containment of CO₂ required by regulators. This article presents a comparison between CO₂ EOR and CCS for injection well metallurgy and explains why this comparison is invalid.

Background and Comparisons

There is a 50-year successful history of CO₂ EOR in petroleum production that has led to a consensus, largely without merit, that corrosion of injection-well equipment is manageable and does not result in long-term degradation of certain components such as casing.

The reason there is little or no merit to applying this experience to CO₂ CCS wells is the lack of data specific to the long-term corrosion resistance of casing that remains in the EOR wells. Rather, the industry generally simply plugs these wells with cement, and in the majority of cases without examining the casing before abandoning. Furthermore, industry rarely returns to inspect them after years of abandonment.

In a few instances, logging and retrieval of cement cores and casing have been performed and analyzed. For example, analysis of cement and casing from the SACROC field that had been exposed to CO₂ for over 30 years showed corrosion along the casing-cement interface (Carey et al. 2007). Laumb et al. (2016) reported substantial casing corrosion for a CO₂ EOR well in the Weyburn field based on a series of logs over several years. Koplos et al. (2007) provided survey data from numerous CO₂ EOR wells and found that 11.1% of the wells failed mechanical integrity tests and concluded that injection-well mechanical integrity is a concern for CO₂ injection and storage due to the corrosivity of CO₂ on downhole materials.

There are also many factors that are significantly different between these two methods of CO₂ injection. For one, EOR wells are typically shallower than CCS wells, and therefore the temperatures and pressures are often lower than for CCS. Moreover, the formations are often uniquely different. In the case of EOR, the formations are often partially depleted reservoirs containing some amount of oil in place that can moderate the corrosivity. In the case of CCS, the formations are typically high-salinity, nonpotable aquifers.

Another important difference between EOR and CCS wells is that historically the source CO₂ for EOR was from gas plants that had few impurities such as typically H₂S or occasionally small amounts of mercaptans. On the other hand, CCS injectate streams can contain numerous impurities depending on the source of the CO₂ that can have a significant impact on corrosion of downhole equipment. These impurities are rarely seen in EOR.

Another important difference between EOR and CCS wells is the permitting requirements. In most cases EOR wells are covered under EPA Class II wells while CCS and CCUS are required to conform with EPA Class VI requirements.

The EPA requirements for Class VI wells are:

“Ensure that the materials planned for all well components are compatible with the planned injectate and formation fluids that may be encountered, and that they can resist corrosion for the duration of the project.”

Similar language is included in 40 CFR Part 146 Subpart H for Class VI wells.

"All well materials must be compatible with fluids with which the materials may be expected to come into contact …”

First of all, carbon-steel casing is never considered corrosion resistant under any circumstances, and secondly, the design life of many CCS wells can be 30 years or longer. Specifically, the EPA requires post-injection site care for 50 years after injection.

There are no such requirements specific to casing, tubing, packers, etc. for Class II wells.

Under no circumstances can carbon-steel tubulars be characterized as corrosion resistant; therefore, corrosion-resistant alloys (CRAs) must be considered for components exposed to the reservoir fluids in contact with CO₂. The selection of the appropriate CRA for a specific well environment is a complicated process as detailed elsewhere (Craig, Rowe, and Doll et al. 2023).

Also, for Class VI wells but not required for Class II and EOR wells:

“The Class VI Rule requires Class VI permit applicants to develop and implement a comprehensive testing and monitoring plan for their projects that includes injectate monitoring, corrosion monitoring of the well’s tubulars, etc.”

Similar language is again reflected in the CFR. It is required that corrosion monitoring be performed with corrosion coupons or loops according to Class VI permitting, and that mass loss and thickness loss be measured.

This requirement implicitly assumes coupons are made from carbon steel which is not the case for the use of CRAs in the injection zone. By and large, CRAs don’t suffer from mass loss or thinning in these CO₂ injection streams. Rather if they are susceptible to corrosion, it will take the form of pitting or crevice corrosion which in many cases will not be observed on coupons.

Conclusions

Since there are currently no standards or guidelines on what would be considered acceptable corrosion damage to casing and tubing in CCS wells, and since Class VI wells are required to resist corrosion for the duration of the project, the only choice for these components when water is expected to be present is CRAs.

For Further Reading

Analysis and Performance of Oil Well Cement With 30 Years of CO2 Exposure From the SACROC Unit, West Texas, USA by J. William Carey, et al. International Journal of Greenhouse Gas Control (2007).

Wellbore Corrosion and Failure Assessment for CO2 EOR and Storage: Two Case Studies in the Weyburn Field by J. Laumb et. al. International Journal of Greenhouse Gas Control (2016).

A Review of Injection Well Mechanical Integrity by J. Koplos, et. al. IEA Greenhouse Gas R&D Programme 3rd Well Bore Integrity Network Meeting, 12–13 March Santa Fe, New Mexico (2007).

Guidelines for the Selection of Corrosion Resistant Alloys for CCS and CCUS Injection Wells by B. Craig, A. Rowe, M. Warmack, et al. International Journal of Greenhouse Gas Control (2023).

Summary of Carbon Dioxide Enhanced Oil Recovery Injection Well Technology by J. Meyer. API (2007).

Carbon Dioxide Enhanced Oil Recovery. NETL (2010).

CO2 Miscible Flooding for Enhanced Oil Recovery by A. El-hoshoudy and S. Desouky. IntechOpen (2018).

Bruce Craig is an SPE member and subject matter expert in metallurgy and corrosion with MetCorr in Denver, Colorado. He holds BS, MS, and PhD degrees in metallurgical engineering from the Colorado School of Mines. For more than 40 years, Craig has been involved with the selection of the facilities metallurgy for oil and gas projects around the world, including Mobile Bay in the Gulf of Mexico (shallow water), deepwater Gulf of Mexico, the Rocky Mountains, Asia, and the Middle East. In addition, he has most recently been involved in metallurgy selection for CCS and CCUS injection wells.

Adam Rowe is an SPE member and principal metallurgical engineer with Stress Engineering Services in Houston. He holds BS and MS degrees in metallurgical and materials engineering from the Colorado School of Mines. Rowe has specialized expertise in material evaluations, corrosion assessments, welding metallurgy, additive manufacturing, and metallurgical failure analyses. He has worked on a large variety of projects across several different industries, and recent project experience includes addressing manufacturing, fabrication, and corrosion concerns in CCS, hydrogen storage, and offshore wind developments.