Safe and secure CO₂ storage requires that the injected CO₂ does not escape to the surface, contaminating aquifers along the way and possibly endangering the ecosystem. Layer continuity, faults, and chemical reactions with the rocks are some of the key questions being addressed to ensure that the cap rock and the regional faults will retain their sealing properties while being pressured up again during the injection process. In parallel, a key challenge is to demonstrate the sealing properties of the wells in contact with CO₂ reservoir: P&Aed wells, producers, monitoring wells, injectors … Well integrity appears to be one of the major concerns as it can be the vector for CO₂ migration from the reservoir to gas or water bearing formations, freshwater aquifers or to the surface. The injections especially using existing wells can also have an impact on the integrity of those wells. A risk-based performance approach has been developed as a useful and reliable decision making support for well integrity management strategies. It relies on a systemic modeling of the well, a multi issues approach and probabilistic gas migration quantification. This quantification takes into account the impact of the injection phase and the effect that it could have for long term on the overall containment system. This methodology was successfully applied to industrial projects of CO₂ injection and storage. Using real-case applications, we present the basic principles of the approach along with the flow of information, from required input data to decision support for performance-optimized solutions. Supported by numerical models including degradation mechanisms, gas flow and uncertainties management related to the well’s characteristics, methodology provided a comprehensive well integrity risk-based assessment in the form of a quantitative risk mapping over several hundreds of years. The scenarios ranking was then proposed and revealed that well candidates would suit best for conversion into injectors. Once sources of risk were identified, solution for unacceptable risk mitigation were proposed and ranked to determine the most suitable recommendations for performance management. Recommendations of targeted actions on sources of risk were provided in the form of operational decision trees for well integrity performance management.

André GARNIER¹; Jean-Benoît LAUDET¹, Nadine NEUVILLE², Yvi LE GUEN², Dominique FOURMAINTRAUX², Jian-Fu SHAO³, Nicolas BURLION³, Noureddine RAFAI⁴

⁽¹⁾Total SA, ⁽²⁾OXAND, ⁽³⁾LML, ⁽⁴⁾LERM

Context
One of the major technological issues for CO2 injection (for EOR, CCS) or H2S injection (natural gas desulphurization) is the long-term behavior of cement-based materials used to ensure the overall sealing performance of the wells, as when water is present, CO2 and H2S could chemically react with the cement. How CO2 or H2S enriched fluids may change cement chemistry and properties? Could the sealing performance of the wells be affected by these changes?

Objectives
Experimentally assess the phenomenology and the kinetics of the changes occurring in a class G neat cement exposed to aqueous fluids enriched with CO2 or H2S at down hole conditions.

Static Tests Experimental program
The “static” experimental set-up simulates the conditions of cement sheath at down-hole conditions: the samples were immerged in water in a vessel pressurized by CO2, or H2S, and thermally regulated (all samples were prepared according to the ISO/API specifications):

• Test 1: neat class G cement, 100% CO2, pressure (gaseous CO2 above water): 8 MPa (1,160 psi) and temperature: 90°C (194° F);
• Test 2: neat class G cement, 100% H2S, pressure (gaseous H2S above water): 1.5 MPa (218 psi) and temperature: 90°C (194°F).

Cement specimens experimented various exposure time-periods (from one week to 3 months) and were characterized using advanced methods for chemical and mineralogical analysis (X-ray tomography, SEM, XRD, TGA-TDA…).

Static Tests Main results

• In the presence of CO2:
• A carbonation front (i.e. precipitation of calcium carbonates) progresses from the interface with the fluid towards sample center;
• Decrease in porosity;
• Increase in mass.
• In the presence of H2S:
• Lixiviation front (i.e. dissolution of cement hydrates) progresses from the interface with the fluids towards sample center;
• Rapid diffusion of sulfur toward sample (faster than lixiviation front);
• Significant increase in porosity;
• Drop in samples mass;

Dynamic Tests preliminary results
Coupled mechanical & chemical tests for both CO2 & H2S will be described (acid gas enriched water injection in a cement sample under deviatoric stress) and preliminary results discussed.

Next steps

• What is the impact of CO2 and H2S in other pressure/ temperature conditions?
• What is the behavior of cement designed to resist to CO2 and H2S attacks?

Dias S.⁽¹⁾, Le Guen Y.⁽¹⁾, Poupard O.⁽¹⁾, Shtivelman V.⁽²⁾

⁽¹⁾Oxand France, ⁽²⁾Geophysical Institute of Israel

One of the work packages of MUSTANG (MUltiple Space and Time scale Approach for the quaNtification of deep saline formations for CO2 storaGe) EU project is dedicated to developing a generic methodology for risk assessment related to CO2 in saline aquifers and applying the methodology to an experimental site. This paper presents the work done by OXAND regarding risk assessment and the application of a risk-based approach to the qualification of the storage site ultimately to provide guidelines for further industrial storage projects. The risk assessment process is presented, and illustrated with the data of an experimental site. The eight steps of the risk assessment process highlighted in the ISO 31000 are described in this paper: risk management policy, establishment of the context, risk identification, risk estimation, risk evaluation, risk treatment, communication and consultation, and monitoring and review.

Poupard O.⁽¹⁾

⁽¹⁾Oxand France

Long-term well integrity plays a key role in the overall performance of O&G storage project, in particular for acid gas storage (CO2, H2S ...). In fact well integrity issues may be considered to be a possible leak path for acid gases and thus detrimental to long time containment in the geological storage system. Therefore, managing long-term well integrity performance is one challenge that must be addressed to demonstre the safety of such projects. A detailed assessment of the long-term well integrity performance is a challenging task. First, the properties of the well barriers, which ensure well integrity, always remain partially unknown. As a consequence, uncertainties must be considered when evaluating long-term well integrity performance. Second, these well barriers are subject to degradation processes, which start to occur from the day the well is spudded. A risk-based approach is proposed to manage the well lifecycle over long term. It includes the multi-stakes of system, investigation of all available data (logs, drilling and completion reports ...) and a predictive model integrating the uncertainties to quantify the possible gas flow along the wellbore. A phase flow model based on Darcy's law has been integrated and is coupled to degradation phenomena of well's components (cement leaching, corrosion, themro-mechanical effect ...). The methodological framework utilizes the concept of risk as a critical criterion to; firstly, evaluate the overall well integrity performance with respect to different stakes; secondly, include the different levels of uncertainty, which characterize complex systems over a long-term time frame; and thirdly, provide reliable support for an optimal performance management strategy. Efficiency of further characterization, specific monitoring or proactive remedial actions can then be estimated and recommendations made in total objectivity.

Garnier A.⁽²⁾, Laudet JB.⁽²⁾, Neuville N.⁽¹⁾, Le Guen Y.⁽¹⁾, Fourmaintraux D.⁽³⁾, Rafai N.⁽⁴⁾, Burlion N.⁽⁵⁾, Shao JF.⁽⁵⁾

⁽¹⁾Oxand France, ⁽²⁾TOTAL E&P, ⁽³⁾DF Ingénierie, ⁽⁴⁾LERM, ⁽⁵⁾LML

One of the major technological issues for CO2 injection (for EOR, CCS, etc.) is the long-term behavior of cement-based materials used to ensure the overall sealing performance of the storage wells. When water is present, the CO2 after injection can react chemically with the cement (i.e. carbonation). How do the CO2-enriched formation fluids changes the cement's chemistry and properties... Could the sealing efficiency of the wells be affected by these changes... The objectives of our experimental program are to assess the kinetics and phenomenology of the changes that occur in different class-G Portland cements exposed to CO2-enriched aqueous fluids at 8 MPa and two different temperatures. The experimental program presented in this paper consists of: a first carbonation test (Test # 1) using neat G cement, at a temperature of 90°C (194°F) and a pressure (supercritical CO2 above water) of 8 MPa (1160 psi); a second carbonation test (Test # 2) using G cement with silica flour (to prevent strength retrogression), at a temperature of 140°C (284°F) and at the same CO2 pressure of 8Mpa. Finally, coupled chemo-mechanical tests (dynamic tests) are underway on similar class-G cement and similar CO2-rich water. All the samples were prepared according to ISO/API specifications. The experimental set-up simulates downhole "static" conditions: the samples were immersed in water in a cell thermally regulated and pressurized by CO2. Cement samples were exposed to CO2-saturated water for various lengths of time (from one week to 3 months) and were characterized using advanced methods for chemical and mineralogical analysis (X-ray tomography, SEM, XRD, TGA-TDA...) and mechanical testing. The main preliminary results show a reactive front (characterized by carbonation) progressing from the fluid-sample interface towards the sample centre. The carbonation front moves faster during Test 2 (at higher temperature) than during Test 1 (at lower temperature). SEM images of Test 2 also show a thin layer of dissolved carbonate at the sample's surface. The carbonated cement areas exhibit increased density and greater compressive strength. The results of coupled chemo-mechanical tests with injection of CO2-enriched water in samples under deviatoric stress show that the CO2 flow rate in the cement rapidly decreases, finally resulting in carbonation clogging of the cement sample. These results seem consistent with reported field observations.

Le Guen Y.⁽¹⁾, Huot M.⁽¹⁾, Loizzo M.⁽²⁾, Poupard O.⁽¹⁾

⁽¹⁾Oxand France, ⁽²⁾Schlumberger

Given the global interest in reducing greenhouse gas emissions, the 18 member CO2Sink consortium was formed to develop a pilot CO2 sequestration project near the town of Ketzin, Germany to advance the knowledge and understanding of CCS as a method of reducing CO2 emissions. This project includes 2 monitoring wells and 1 injection well, for a total injection of 30,000 tonnes of CO2. Among the projects associated with the Ketzin injection site, the COSMOS 2 research project was initiated as a partnership between France and Germany. The project includes, among others activities, the evaluation of the injection well (Ktzi-201) integrity. This was performed through extensive modeling using P&RTM approach and SIMEOTM Stor platform to simulate possible CO2 leakage along the wellbore over a 1,000-year period and a resulting risk assessment. Various case studies were tested: whereas risk levels tend to be low for a pilot project (i.e. low CO2 reservoir pressure), treatment actions could be required for industrial scale projects (i.e. greater CO2 reservoir pressure), such as additional characterizations, workovers, or an advanced abandonment strategy. These actions could decrease either the probability of the risk, or the severity, or both, ensuring effective CO2 confinement demonstration over the long-term. This study provides objective support in decisions regarding well management of the CO2 Ketzin project.

Botnen L.⁽³⁾, Sorensen J.⁽³⁾, Steadman E.⁽³⁾, Harju J.⁽³⁾, Ayash S.⁽³⁾, Giry E.⁽¹⁾, Frenette R.⁽¹⁾, Meyer V.⁽²⁾, Moffatt D.

⁽¹⁾Oxand Canada, ⁽²⁾Oxand France, ⁽³⁾Energy & Environmental Research Center, University of North Dakota

This paper describes the application of an original, carbon capture and storage (CCS)-specific risk management methodology to the subsurface technical risks of Spectra Energy's Fort Nelson CCS feasibility project located in British Columbia:

• Phase 1: Establishment of a risk management policy utilizing input from key project stakeholders to help define a project-specific metric system (frequencies, physical consequences, severities) for the estimation of technical risks.
• Phase 2: A first-risk assessment of the subsurface technical risks, including risk mapping and evaluation of high-criticality risks.
• Phase 3: A risk treatment plan and first recommendations for a risk-based monitoring, verification, and accounting (MVA) plan based on the results of the risk assessment.