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A review on well integrity issues for CO2 geological storage and enhanced gas recovery
Renewable and Sustainable Energy Reviews 59 (2016) 920–926
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Renewable and Sustainable Energy Reviews journal homepage: www.elsevier.com/locate/rser
A review on well integrity issues for CO2 geological storage and enhanced gas recovery Mingxing Bai, Zhichao Zhang, Xiaofei Fu n Department of Petroleum Engineering, Northeast Petroleum University, 163318, China
art ic l e i nf o
a b s t r a c t
Article history: Received 24 February 2015 Received in revised form 7 January 2016 Accepted 13 January 2016
The world’s rapid economic growth has contributed to the ever increasing demand for energy which results in the increase of fossil fuels usage. On the other hand, renewable energies, which are considered environmentally friendly, cannot replace the fossil fuels in the short term. For this, CO2 capture and storage (CCS) technologies could work as transitional technology. To ensure a meaningful underground storage, well integrity is potentially the greatest challenge. On one hand, the injected CO2 may cause severe corrosion to metallic tubulars and cement in the wellbore. Identification, quantification and mitigation of this corrosion are the key to achieve satisfactory well conditions. On the other hand, the mechanical integrity loss due to cyclic and thermal loading in the well life will also occur, so to investigate and evaluate well integrity is of paramount importance to ensure a safe operation and storage. This paper presents a definition of well integrity in the scope of CSEGR as well as the mechanisms of well integrity loss. Overview on corrosion issues of metallic and cement corrosion along with the remedial measures is discussed. Through a thorough literature review, well integrity criteria for new and old wells are introduced to provide a guidance for material selection for the usage in CSEGR. Moreover, in order to evaluate the integrity of operational and abandoned wells, this paper provides a review on the existing monitoring methods, as well as risk based methods such as FEPs analysis, Performance and Risk Management, CO2-PENS, and put forward a new concept of well integrity evaluation. & 2016 Elsevier Ltd. All rights reserved.
Keywords: Well integrity Cement corrosion CO2 underground storage Abandoned well
Contents 1. 2.
3.
4. 5.
n
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921 Mechanisms responsible for a loss of well integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921 2.1. Influences of well life phases on well integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921 2.2. Corrosion issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 2.2.1. Metallic corrosion mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 2.2.2. Cement corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 Well integrity criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 3.1. New wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 3.1.1. Casing strings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 3.1.2. Tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.1.3. Packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.1.4. Well completion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.2. Existing wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.2.1. Operational wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.2.2. Abandoned wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 Determination of well integrity for operational wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924 Risk based approaches for abandoned wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924 5.1. FEP (Features, Events and Processes) based method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924 5.2. A new concept for well integrity evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925
Corresponding author. E-mail address: [email protected] (X. Fu).
http://dx.doi.org/10.1016/j.rser.2016.01.043 1364-0321/& 2016 Elsevier Ltd. All rights reserved.
M. Bai et al. / Renewable and Sustainable Energy Reviews 59 (2016) 920–926
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6. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925 Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 926 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 926
1. Introduction Rapid economic growth has contributed to the world’s ever increasing demand for energy. An obvious consequence of this is an increase in the use of fossil fuels such as coal, oil and natural gas, which are considered to have adverse effects on the environment. However, alternatives, such as renewable energies, are currently more costly than the more mature fossil technologies, and cannot replace the fossil fuels. CO2 capture and storage (CCS) technologies could work as transitional technology, reducing the CO2 emissions from the energy sector before a transition to less carbon-intensive energy system is achieved. Geological storage of CO2 in the underground space such as depleted oil and reservoirs, saline aquifers and coal seams, is considered to alleviate the greenhouse effect on the environment and improve oil and gas recovery. It has been successfully applied around the world in the past decade. Examples are RECOPOL (Reduction of CO2 emission by means of CO2 storage in coal seams in the Silesian Coal Basin of Poland), enhanced Coal Bed methane production by CO2 injection in Allison Unit in Mexico, the first commercial CCS (CO2 Capture and Sequestration) project in Sleipner gas field in Norway [1], the CCS project launched by several large companies like BP and Statoil in In Salah gas field located in Algeria, and the CCS project in the depleted gas field Ketzin in Germany. This work is based on a CO2 Large–scale Enhanced Gas Recovery project in the Altmark Natural Gas Field in Germany which is the second largest onshore gas field in Europe. The natural gas is contained in the geological Rotliegend formation in a depth of approx. 3500 m and above it there is a geological barrier consisting mainly of Zechstein salt layer [2,3]. The injected CO2 is retained underground by different mechanisms including hydrodynamic trapping, solubility trapping, and mineral trapping depending upon the prevailing subsurface conditions. Hydrodynamic trapping means the injected CO2 will be trapped as supercritical fluid and will be free to rise up by buoyancy effect until it reaches the cap rock where it will accumulate. Solubility trapping relies on the principle that CO2 is highly soluble in water when injected in depleted gas fields. Mineral trapping means CO2 can react with the minerals and organic matter present in the formation to become part of the solid matrix. In comparison with other types of CCS, Carbon Dioxide Sequestration and Enhanced Gas Recovery (CSEGR) gained much more popularity because it can not only provide pressure support to prevent subsidence and water intrusion, but also improve gas recovery via both displacement and re-pressurization of the remaining natural gas, as shown in Fig. 1. The injected CO2 usually stays in supercritical state at the temperatures and pressures prevalent in the field (greater than 31 °C and 73.8 bar), so the near gas-like viscosity of supercritical CO2 allows a high injectivity in the formation. A typical depleted gas reservoir holds more storage capacity than depleted oil reservoir. Besides, high compressibility of CO2 makes it a more efficient cushion gas which will facilitate storage of more gas for a given pressure [4,5]. Geological CO2 sequestration is associated with certain potential risks, for example, CO2 migration to the surface after injection, CH4 leakage, subsidence or uplift due to pressure changes. Most of the risks result from loss of caprock or wellbore integrity. Well integrity, which poses potentially the greatest risk to CSEGR operations, are the most manageable. It is referred to as the
application of all technical, operational and organizational solutions to reduce or mitigate the risk of uncontrolled release of formation fluids to the surface throughout the entire life cycle of wells [6]. The wells involved in CSEGR have to meet the requirement of successful long term retention of the injected CO2 over the operation phase involving injection of supercritical CO2 and geological storage phase. Based on the CCS project in the pilot area, the authors have performed a thorough review on the issues related to well integrity, including mechanisms for loss of well integrity, well integrity criteria, well integrity investigation and evaluation and so on.
2. Mechanisms responsible for a loss of well integrity The outcome of a loss of well integrity in CSEGR is the creation of different leakage pathways for the ascent of CO2, as shown in Fig. 2. Leakage along these pathways may occur through or along abandoned wells and improperly constructed operative wells during the injection of CO2 and production of natural gas. The abandoned wells, especially the ones which are improperly plugged and abandoned, are potentially the preferred migration pathway for CO2 to escape [2,3]. The mechanisms responsible for a loss of well integrity are subdivided into chemical loading, mechanical–thermal loading and construction defects [8]. 2.1. Influences of well life phases on well integrity Well life phases such as drilling, completion, production, and abandonment involve characteristic operations which impose the following influences on well integrity. Geomechanical damage encompasses any stress-induced changes in the hydraulic conductivity properties of materials within the wellbore system. Hydrochemical damage refers to any alteration of hydraulic conductivity in the near well formation region, typically known as formation damage. Mud removal efficiency is the one with which the mud is removed from the annulus during cementing operations and addresses the development of mud channels and its impact on hydraulic integrity of the wellbore. Cement deterioration damage refers to porosity alteration due to geochemical processes under in-situ conditions. Last but not least, the wells drilled through salt sections can potentially pose well integrity
Fig. 1. Schematic diagram of the wellbore zone [7].
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Fig. 2. Leakage pathways [8].
problems over the length of salt interval, because salt creeps and deforms in a different way from typical rocks especially in heterogeneous layers where the salt layer will expand but other layers will not expand which will result in setting up shear stresses and bedding plane slips [9]. During and post CSEGR operations the salt layers can act as natural barriers to the migrating CO2 in addition to the cement plugs and sheath due to their impermeability. Obviously, geomechanical damage due to salt layers poses potentially low risk. The stage that will bear the highest impact will be cement deterioration, which results in loss of strength accompanied by porosity increase. 2.2. Corrosion issues Corrosion of different well components, e.g., casing, cement, and other downhole completion components, is the aspect bearing the highest impact on the technical and economical feasibility of operations as well as the success of the project. 2.2.1. Metallic corrosion mechanism There are usually several types of metallic corrosion. Galvanic corrosion occurs when two dissimilar metals are in a conductive medium and develop a potential difference between them. Crevice corrosion is a localized type of corrosion occurring in systems containing oxygen and is most intense when chlorides are present [10]. In the presence of an aqueous phase CO2 dissolves in water to produce carbonic acid (H2CO3) which promotes an electrochemical reaction with steel [11]. The resulting carbonic acid is corrosive and forms a scale of iron carbonate as corrosion product on the surface of the metal. CO2 also causes embrittlement resulting in stress corrosion cracking. The presence of H2 in the reaction may lead to embrittlement [10]. Besides, collapse of small bubbles within high velocity fluids create shock waves of high pressure, resulting in loss of metal from the surface in contact, usually found on the pump impellers. 2.2.2. Cement corrosion Portland cement is most commonly used for well cementing purpose. When CO2 is dissolved in water, it forms carbonic acid (HCO-3) which reacts with compounds in hydrated Portland cement matrix such as calcium silicate gel (C–S–H) and calcium hydroxide (Ca(OH)2). The major reaction products are calcium carbonate and amorphous silica gel. Leaching of the resulting
CaCO3 and Ca (HCO3)2, leads to rapid reduction in strength, varied permeability, and corrosion on the casing [12–14]. Various experiments have been conducted to study the influence of temperature, pH, CO2 differential pressure, cement composition, additives on the cement degradation, and the alteration process versus time [15–18]. It is generally considered that temperature has more influences on degradation than pH. A pH of 2.4 and 50 °C represents conditions for the most severe degradation which is analogous to sequestration at a depth of 1 km in sandstone formation according to a study by [15]. Corrosion can be deemed as critical in case there are already defects such as channels, micro-annuli and small cracks [19], so it is equally important that the cement sheath be mechanically durable to withstand severe stresses experienced throughout the life of the well [37]. To repair the composite system behind the casing involves healing the defects by squeezing, for example, cementitious materials. The cement selected for a squeeze cementation or drilling a new well exposed to CO2 has to be no less resistant to CO2 corrosion than the cement in the cement sheath. For this, more than 50 additives can be added to provide optimum slurry characteristics for severe downhole conditions. For example, the addition of Pozzolan can reduce permeability and reduce corrosion rates by 50% and 70%, respectively, according to an experiment performed by the authors. Salt water usage in Portland cement reduces the corrosion rate up to 10%. Microfine cements with average and maximum particle size of 4–6 and 15 μm can penetrate relatively small fractures [20]. The use of latex cement, which is blends of API Class A, G or H cement with the polymer latex added, can resist acid corrosion and improve the hardened cement’s elasticity and bonding strength of the cement slurry [21,22].
3. Well integrity criteria The well integrity criteria for the wells in CSEGR, either newly drilled wells or existing wells, have to meet the requirements for safe and long-term storage. 3.1. New wells An injection well and production well, is drilled, if necessary, during CSEGR operations to inject supercritical CO2 and produce natural gas accompanied by formation water and CO2, respectively. Although the drilling program for CO2 applications is not different from the conventional ones, the minimization of formation damage is critical so that near wellbore formation does not provide leakage pathways. Experiences have been gathered on the injecting well experience for various CO2 injection projects in and outside USA, and the materials selection for the well components have been summarized. But it is not applicable to every CCS case since the reservoir conditions and the expected purposes of CCS are not always the same [38]. 3.1.1. Casing strings For newly drilled wells, the casing is generally recommended to be set in the middle of the caprock and the liner overlap length should be minimized as well. The nature and magnitude of the downhole corrosive environment in case of high reservoir water saturation or W-A-G (Water Alternating Gas) method of injection, promotes rapid corrosion of casings. The part of casing below the packer is prone to carbonic acid and therefore warrants corrosion resistant alloy. Since the liner is difficult to replace, so the choice for corrosion control in terms of material selection is of paramount importance. Common methods are the usage of corrosion resistant alloys like Duplex stainless steel or lined material such as Glass
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Reinforced Epoxy (GRE), Internal Plastic coating (IPC). But material like IPC may be unsuitable for liners since perforation will cause damage to the integrity of the material, resulting in CO2 entering the lined material and corrosion of exposed metal surface [11]. 3.1.2. Tubing Similarly to casing strings, the part of tubing below the packer suffers corrosion severely and this part of tubing must be made of corrosion resistant alloys. In case of CO2 stream contaminated by H2S, it is found that injection tubing made of seamless L-80 material with Hydfil CS premium connections can prevent Sulfide Stress Cracking (SSC). Also larger diameter tubing will facilitate installation of a larger size of Wireline Retrieved Surface Controlled Subsurface Valve (WRSCSSV) as well as future coiled tubing workover. Composite lined material like Glass Reinforced Epoxy (GRE) linings, Internal Plastic Coatings (IPC), thermoplastic coatings such as High Density Polyethylene (HDPE) and Polyvinyl Chloride (PVC) are more commonly used as corrosion barriers for injection tubing [23]. The use of corrosion inhibitors can be made along with corrosion resistant alloy tubing, to prolong the tubing life. Although it does not prevent corrosion, it can reduce it to an acceptable level before workover is made.
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increase CO2 pressure to the required injection pressure and it is equipped with suction scrubbers and discharge cooler for each of the four compression stages [21]. The suction scrubbers remove traces of liquids in the stream and the coolers remove heat generated in compression. For the material of the construction of coolers, downstream piping, vessels and other equipments, stainless steel is recommended. The production well for CSEGR includes the surface equipment much as the conventional oil and gas wells. According to a scientific report about failures of completion components of production wells by the Sheep Mountain Unit (SMU), wing valve replacement was 52% while master valve replacement was 28%. So they must be given more consideration when designing a production well [24]. 3.2. Existing wells
3.1.3. Packer The location of a packer, whether the completion components or casing is above or below it, provides a reference for material selections, and also assists in risk assessment. The production packer elements should be chemically inert to the CO2 and H2S environment at high temperatures prevalent downhole, and the packer body should be made of corrosion resistant alloys, so that they can have a long service life in hostile corrosive conditions. For the packers used in Jedney Field in Canada for disposal of acid gas, the inner mandrels and packer bodies were made of Incoloy. The packer elements were specially formulated source of spec nitrile rubber while the seal assemblies were made of AFLAS acid resistant materials [21]. The packer fluid to be selected should be resistant to acidic waters as well.
3.2.1. Operational wells The existing operational wells to be used in CSEGR for either injection or production purposes, shown in Fig. 3(a), are confronted with more constraints in comparison with new wells. To select an appropriate well for CSEGR operations one has to consider whether the well is currently used for injection or production. This consideration confirms the availability of necessary infrastructure such as injection or production surface facilities, well head and other associated completions. Favorable presence of the above components reduces the cost of replacing components or workover. However, the casing size, in some cases, might limit the completion options and well interventions. Secondly, water injection wells, which are known to suffer from corrosion and erosion due to high water velocity during injection, might be unsuitable for CSEGR. Last but not least, CSEGR warrants injection of CO2 below a certain depth with consideration to factors such as cap rock location, saline aquifer location, and geomechanical issues, depending upon the reservoir conditions, geology and storage mechanism of CO2, so it is important to determine whether the required depth of injection is above or below the cased depth.
3.1.4. Well completion The injected CO2 is compressed through multi-stage compressors accompanied by liquid removal and dehydration in every stage to prevent the formation of corrosive carbonic acid. A fourstage centrifugal or reciprocating compressor system is used to
3.2.2. Abandoned wells When a well is no longer needed, it has to be plugged and abandoned according to local mining regulations and guidelines. The typical procedures to abandon a well in Germany involve firstly shut off the connection to the reservoir using a bottom
Fig. 3. (a) Operational well structure (b) plugged and abandoned well [8].
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cementation. Additional cement plugs are placed where potential problem zones are, e.g., above the liner, in combination with mechanical plugs, if necessary. Heavy drilling fluid with Bentonite added is filled into the space in between these plugs. In the near surface, the casings are cut a length of minimum 1 m for onshore wells and 5 m for offshore wells and covered by a cement plate or a steel plate, as shown in Fig. 3(b) [7]. The well integrity criteria for abandoned wells are inherently different from operational wells because the abandoned wells being out of service are not subjected to any type of monitoring activities. Also the geomechanical changes in the near wellbore region are unknown since the abandonment of the well. The residual strength of the material will be a decisive factor to decide whether the casing will maintain the well integrity or not. The state of the casing in terms of the mechanical integrity and corrosion should be investigated. Since the data available does not suffice for a direct assessment, some indirect methods such as risk assessment are used [2,25,26]. More explanation can be found in the following section of this paper.
condition. Identification of channels in cement and tubular damage is possible, thereby revealing the status of zonal isolation for remedial work. Cement Bond Log (CBL) is often used to evaluate the quality of primary cementation job by giving the compressive strength of the cement and Bond Index (BI). The CBL readings are affected by casing size, casing thickness and borehole fluids. However, in absence of Variable Density Log (VDL) and transit time (TT), CBL alone cannot indicate cementation problems such as channeling, micro-annulus and bonds between interfaces and so on. In addition to above mentioned tests, there are also some other methods to investigate the well conditions, e.g., noise log, production logging, oxygen activation method, isolation scanner, ultrasonic casing imager and so on. Table 1 shows the strengths and weaknesses of the Schlumberger tools CBL, USIT und Isolation Scanner. It can be seen that logging tools have advanced to the point that they can identify and characterize most defect which can provide pathways for liquids and gases [8].
4. Determination of well integrity for operational wells
5. Risk based approaches for abandoned wells
Migration of the injected CO2 along the wellbores should be monitored to avoid unacceptable leakage. The variety of monitoring techniques can be grouped into several families, each one having its own range application [39]. Examples are Standard Annulus Pressure Test (SAPT), Radioactive Tracer Survey (RATS), Temperature Log (TL), Ultra Sonic Imager (USI), Ultrasonic Casing Imager (UCI), Cement Bond Log (CBL) and so on [27,28]. The SAPT test relies on the principle that pressure applied to a closed system, e.g., annulus between casing and cement, will be maintained if there are no leaks in the system, even if the pressure source is removed. It is easy to interpret, and inexpensive to perform. However, it is unable to detect bad primary cement jobs, or leakage by-passing the shoe. RATS involves addition of radioactive (RA) tracers to the injected fluid and then with the RA detector which is run on wire line to detect the tracers. It is expensive, and difficult to handle radioactive materials. Temperature Log is a record of temperature gradient of a well with geothermal gradient as a reference, taken before production or recorded when well is shut-in. Interpretation is done by looking for anomalies or departures from reference gradient, which are related to entry of fluids in borehole or exit in the formation. Interpretation of temperature log is difficult and requires high expertize. USI gives an accurate and high-resolution, real-time information about pipe-to-cement bond quality and downhole pipe
5.1. FEP (Features, Events and Processes) based method
Table 1 Wireline tool comparison for characterization of leakage pathways [8].
Structured methods have been developed and successfully applied to evaluate the technical integrity of a repository for radioactive waste. The expertize has been transferred to well integrity evaluation in CCS applications [2,29]. The method comprises two steps, which are scenario development and consequence analysis. The Features, Events, and Processes (FEPs) are essentially all activities influencing the storage of CO2 in the long term. Scenarios describe the possible future developments of a system under consideration, defined by a combination of Features, Events, and Processes (FEPS). The developed scenarios are evaluated in the context of consequence analyses. Based on the pilot area, the authors have started from the Quintessa FEP database, which is a generic data base to describe the behavior of the storage system. It has totally 178 FEPs which are categorized as 8 different groups. After screening and supplement of the FEP database, a new case-specific FEP database was obtained to comprehensively describe the storage system. Obviously, FEPs database is only a qualitative way of describing the static characteristics and dynamic performances of a storage system, and it cannot provide a quantitative evaluation. It can be seen as a reference book or an initial help in the early phase of a storage project and provides the basis for modeling [7].
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A Performance and Risk Management (P&R™) method was developed by some researchers and companies [30–32]. This method covers data collection, static and dynamic model development, numerical leakage simulation, risk mapping. The first step of this method is to collect all data and information about the storage system. After that a static model is built, which acts an input into a dynamic model. The core of the dynamic model is a well completion and leakage simulator Simeo™-Stor, which can numerically predict the CO2 leakage along the wellbore over time. Since the data is mostly uncertain, or even not adequate, a risk assessment is often performed which can take the uncertainties into consideration. However, the lack of data for plugged and abandoned wells needs too many assumptions, which leads to a very uncertain evaluation [7]. CO2-PENS (CO2-Predicting Engineered Natural System) is a probabilistic simulation tool designed to incorporate CO2 injection and sequestration knowledge from the petroleum industry to perform risk assessment [33–36]. The model links high level system models (reservoir model) to the process level (wellbore leakage, chemical interaction of CO2) and thus represents a hybrid coupled process and system designed to simulate different CO2 pathways. Simulation of wellbore leakage is complicated since the associated interactions and processes are not yet entirely understood. 5.2. A new concept for well integrity evaluation A comprehensive assessment method was developed with the application in the Altmark natural gas field in Germany [2,25]. It describes the whole near wellbore zone and quantitatively simulates the critical events and processes which influence well integrity and estimate the long-term leakage rate within the storage period. The process of the method comprises three steps which are FEPs (Features, Events and Processes) and scenario analysis, model development and consequence analysis, as shown in Fig. 4. An analysis of FEPs provides an excellent basis for the definition of scenarios which are evaluated in the next step model development. The first model is mechanical integrity model which aims to evaluate the mechanical integrity of the wellbore and provide a quantitative characterization of the defects in the casing–cement–rock composite system, which is then used to estimate the permeability of the casing–cement–rock composite system. A numerical model will be developed to describe the processes and events considered in a scenario in abstract form, so that the leakage rate over a certain time frame can be simulated. In comparison to above-mentioned methods, the proposed method in this paper covers both qualitative and quantitative
Scenario Analysis
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analysis. The goal is to reach a sound risk analysis for well integrity coupling both a thorough FEPs analysis and quantification of the leakage risk of CO2 along a defected wellbore under a series of mechanical and geochemical processes.
6. Conclusions To ensure a meaningful storage of CO2, well integrity of operational and abandoned wells have to be evaluated prior to injection. Many individuals have committed much effort to investigate related issues such as loss of well integrity, well integrity criteria for new and existing wells, as well as well integrity inspection and evaluation. By analyzing the field data and literatures, it is found that mechanical loading and chemical corrosion of cement and tubular are the two aspects resulting in loss of well integrity. As such, materials selection for newly drilled wells or plugging a well has been investigated as well to achieve well integrity for safe operation and storage in CSEGR. Assessment of well integrity for both operational and abandoned wells can be performed in different ways. For operational wells, different tests can be implemented with varying accuracy. However, no logging tool is available which can explicitly detect the presence and extent of corrosion in cement. A commonly used one is CBL complimented with Variable Density Log (VDL) to identify different defects such as channeling, micro-annulus and debonding. For abandoned wells, only indirect risk based method can be used, for example, FEP based method, Performance and Risk (P&R™), CO2-PENS and so on. A new concept has been introduced which couples FEPs analysis, model development and CO2 leakage simulation and consequence analysis. If an application of this method results in a low leakage risk, no further action is required. Medium risks should result in monitoring activities, while high risk wells require reopening and re-plugging. In future, more efforts are required to extend the research on well integrity evaluation of plugged and abandoned wells. Cement based materials are reactive porous media. When exposed to acidic environment, some dissolution/precipitation processes can occur and lead to mechanical and transport properties modifications. The coupled geo-chemical and geo-mechanical effects on cement properties should also be included into a future model. Although a novel and comprehensive methodology has been described in this work, it needs laboratory experiments or field data to verify the results, for instance, the mechanical integrity and the characterization of the defects in the casing–cement–rock composite system, or the self-healing effect of salt rock on the well integrity.
Model Development
Consequence Analysis
Site - specific FEPs Database development
Interaction Matrix between sys. components
Mechanical model development
Selection of most important sys. components
Chemical model development
Scenarios formation
Leakage model development Fig. 4. Flow chart of well integrity evaluation.
Decision making
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Acknowledgments This work is supported by the PetroChina Innovation Foundation (Grant no.: 2015D-5006-0202), Graduate Education Innovation Project in Heilongjiang Province (Grant no.: JGXM_HLJ_2014027), Heilongjiang Postdoctoral Grant (Title: Investigation of the THMC Coupling Effect on CO2 Migration along Casing–cement–rock Composite System), and Technology Project for Returned Oversea Scholars in Heilongjiang Province (2014, Mingxing Bai).
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Contents lists available at ScienceDirect
Renewable and Sustainable Energy Reviews journal homepage: www.elsevier.com/locate/rser
A review on well integrity issues for CO2 geological storage and enhanced gas recovery Mingxing Bai, Zhichao Zhang, Xiaofei Fu n Department of Petroleum Engineering, Northeast Petroleum University, 163318, China
art ic l e i nf o
a b s t r a c t
Article history: Received 24 February 2015 Received in revised form 7 January 2016 Accepted 13 January 2016
The world’s rapid economic growth has contributed to the ever increasing demand for energy which results in the increase of fossil fuels usage. On the other hand, renewable energies, which are considered environmentally friendly, cannot replace the fossil fuels in the short term. For this, CO2 capture and storage (CCS) technologies could work as transitional technology. To ensure a meaningful underground storage, well integrity is potentially the greatest challenge. On one hand, the injected CO2 may cause severe corrosion to metallic tubulars and cement in the wellbore. Identification, quantification and mitigation of this corrosion are the key to achieve satisfactory well conditions. On the other hand, the mechanical integrity loss due to cyclic and thermal loading in the well life will also occur, so to investigate and evaluate well integrity is of paramount importance to ensure a safe operation and storage. This paper presents a definition of well integrity in the scope of CSEGR as well as the mechanisms of well integrity loss. Overview on corrosion issues of metallic and cement corrosion along with the remedial measures is discussed. Through a thorough literature review, well integrity criteria for new and old wells are introduced to provide a guidance for material selection for the usage in CSEGR. Moreover, in order to evaluate the integrity of operational and abandoned wells, this paper provides a review on the existing monitoring methods, as well as risk based methods such as FEPs analysis, Performance and Risk Management, CO2-PENS, and put forward a new concept of well integrity evaluation. & 2016 Elsevier Ltd. All rights reserved.
Keywords: Well integrity Cement corrosion CO2 underground storage Abandoned well
Contents 1. 2.
3.
4. 5.
n
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921 Mechanisms responsible for a loss of well integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921 2.1. Influences of well life phases on well integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 921 2.2. Corrosion issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 2.2.1. Metallic corrosion mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 2.2.2. Cement corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 Well integrity criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 3.1. New wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 3.1.1. Casing strings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922 3.1.2. Tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.1.3. Packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.1.4. Well completion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.2. Existing wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.2.1. Operational wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 3.2.2. Abandoned wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923 Determination of well integrity for operational wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924 Risk based approaches for abandoned wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924 5.1. FEP (Features, Events and Processes) based method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 924 5.2. A new concept for well integrity evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925
Corresponding author. E-mail address: [email protected] (X. Fu).
http://dx.doi.org/10.1016/j.rser.2016.01.043 1364-0321/& 2016 Elsevier Ltd. All rights reserved.
M. Bai et al. / Renewable and Sustainable Energy Reviews 59 (2016) 920–926
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6. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925 Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 926 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 926
1. Introduction Rapid economic growth has contributed to the world’s ever increasing demand for energy. An obvious consequence of this is an increase in the use of fossil fuels such as coal, oil and natural gas, which are considered to have adverse effects on the environment. However, alternatives, such as renewable energies, are currently more costly than the more mature fossil technologies, and cannot replace the fossil fuels. CO2 capture and storage (CCS) technologies could work as transitional technology, reducing the CO2 emissions from the energy sector before a transition to less carbon-intensive energy system is achieved. Geological storage of CO2 in the underground space such as depleted oil and reservoirs, saline aquifers and coal seams, is considered to alleviate the greenhouse effect on the environment and improve oil and gas recovery. It has been successfully applied around the world in the past decade. Examples are RECOPOL (Reduction of CO2 emission by means of CO2 storage in coal seams in the Silesian Coal Basin of Poland), enhanced Coal Bed methane production by CO2 injection in Allison Unit in Mexico, the first commercial CCS (CO2 Capture and Sequestration) project in Sleipner gas field in Norway [1], the CCS project launched by several large companies like BP and Statoil in In Salah gas field located in Algeria, and the CCS project in the depleted gas field Ketzin in Germany. This work is based on a CO2 Large–scale Enhanced Gas Recovery project in the Altmark Natural Gas Field in Germany which is the second largest onshore gas field in Europe. The natural gas is contained in the geological Rotliegend formation in a depth of approx. 3500 m and above it there is a geological barrier consisting mainly of Zechstein salt layer [2,3]. The injected CO2 is retained underground by different mechanisms including hydrodynamic trapping, solubility trapping, and mineral trapping depending upon the prevailing subsurface conditions. Hydrodynamic trapping means the injected CO2 will be trapped as supercritical fluid and will be free to rise up by buoyancy effect until it reaches the cap rock where it will accumulate. Solubility trapping relies on the principle that CO2 is highly soluble in water when injected in depleted gas fields. Mineral trapping means CO2 can react with the minerals and organic matter present in the formation to become part of the solid matrix. In comparison with other types of CCS, Carbon Dioxide Sequestration and Enhanced Gas Recovery (CSEGR) gained much more popularity because it can not only provide pressure support to prevent subsidence and water intrusion, but also improve gas recovery via both displacement and re-pressurization of the remaining natural gas, as shown in Fig. 1. The injected CO2 usually stays in supercritical state at the temperatures and pressures prevalent in the field (greater than 31 °C and 73.8 bar), so the near gas-like viscosity of supercritical CO2 allows a high injectivity in the formation. A typical depleted gas reservoir holds more storage capacity than depleted oil reservoir. Besides, high compressibility of CO2 makes it a more efficient cushion gas which will facilitate storage of more gas for a given pressure [4,5]. Geological CO2 sequestration is associated with certain potential risks, for example, CO2 migration to the surface after injection, CH4 leakage, subsidence or uplift due to pressure changes. Most of the risks result from loss of caprock or wellbore integrity. Well integrity, which poses potentially the greatest risk to CSEGR operations, are the most manageable. It is referred to as the
application of all technical, operational and organizational solutions to reduce or mitigate the risk of uncontrolled release of formation fluids to the surface throughout the entire life cycle of wells [6]. The wells involved in CSEGR have to meet the requirement of successful long term retention of the injected CO2 over the operation phase involving injection of supercritical CO2 and geological storage phase. Based on the CCS project in the pilot area, the authors have performed a thorough review on the issues related to well integrity, including mechanisms for loss of well integrity, well integrity criteria, well integrity investigation and evaluation and so on.
2. Mechanisms responsible for a loss of well integrity The outcome of a loss of well integrity in CSEGR is the creation of different leakage pathways for the ascent of CO2, as shown in Fig. 2. Leakage along these pathways may occur through or along abandoned wells and improperly constructed operative wells during the injection of CO2 and production of natural gas. The abandoned wells, especially the ones which are improperly plugged and abandoned, are potentially the preferred migration pathway for CO2 to escape [2,3]. The mechanisms responsible for a loss of well integrity are subdivided into chemical loading, mechanical–thermal loading and construction defects [8]. 2.1. Influences of well life phases on well integrity Well life phases such as drilling, completion, production, and abandonment involve characteristic operations which impose the following influences on well integrity. Geomechanical damage encompasses any stress-induced changes in the hydraulic conductivity properties of materials within the wellbore system. Hydrochemical damage refers to any alteration of hydraulic conductivity in the near well formation region, typically known as formation damage. Mud removal efficiency is the one with which the mud is removed from the annulus during cementing operations and addresses the development of mud channels and its impact on hydraulic integrity of the wellbore. Cement deterioration damage refers to porosity alteration due to geochemical processes under in-situ conditions. Last but not least, the wells drilled through salt sections can potentially pose well integrity
Fig. 1. Schematic diagram of the wellbore zone [7].
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Fig. 2. Leakage pathways [8].
problems over the length of salt interval, because salt creeps and deforms in a different way from typical rocks especially in heterogeneous layers where the salt layer will expand but other layers will not expand which will result in setting up shear stresses and bedding plane slips [9]. During and post CSEGR operations the salt layers can act as natural barriers to the migrating CO2 in addition to the cement plugs and sheath due to their impermeability. Obviously, geomechanical damage due to salt layers poses potentially low risk. The stage that will bear the highest impact will be cement deterioration, which results in loss of strength accompanied by porosity increase. 2.2. Corrosion issues Corrosion of different well components, e.g., casing, cement, and other downhole completion components, is the aspect bearing the highest impact on the technical and economical feasibility of operations as well as the success of the project. 2.2.1. Metallic corrosion mechanism There are usually several types of metallic corrosion. Galvanic corrosion occurs when two dissimilar metals are in a conductive medium and develop a potential difference between them. Crevice corrosion is a localized type of corrosion occurring in systems containing oxygen and is most intense when chlorides are present [10]. In the presence of an aqueous phase CO2 dissolves in water to produce carbonic acid (H2CO3) which promotes an electrochemical reaction with steel [11]. The resulting carbonic acid is corrosive and forms a scale of iron carbonate as corrosion product on the surface of the metal. CO2 also causes embrittlement resulting in stress corrosion cracking. The presence of H2 in the reaction may lead to embrittlement [10]. Besides, collapse of small bubbles within high velocity fluids create shock waves of high pressure, resulting in loss of metal from the surface in contact, usually found on the pump impellers. 2.2.2. Cement corrosion Portland cement is most commonly used for well cementing purpose. When CO2 is dissolved in water, it forms carbonic acid (HCO-3) which reacts with compounds in hydrated Portland cement matrix such as calcium silicate gel (C–S–H) and calcium hydroxide (Ca(OH)2). The major reaction products are calcium carbonate and amorphous silica gel. Leaching of the resulting
CaCO3 and Ca (HCO3)2, leads to rapid reduction in strength, varied permeability, and corrosion on the casing [12–14]. Various experiments have been conducted to study the influence of temperature, pH, CO2 differential pressure, cement composition, additives on the cement degradation, and the alteration process versus time [15–18]. It is generally considered that temperature has more influences on degradation than pH. A pH of 2.4 and 50 °C represents conditions for the most severe degradation which is analogous to sequestration at a depth of 1 km in sandstone formation according to a study by [15]. Corrosion can be deemed as critical in case there are already defects such as channels, micro-annuli and small cracks [19], so it is equally important that the cement sheath be mechanically durable to withstand severe stresses experienced throughout the life of the well [37]. To repair the composite system behind the casing involves healing the defects by squeezing, for example, cementitious materials. The cement selected for a squeeze cementation or drilling a new well exposed to CO2 has to be no less resistant to CO2 corrosion than the cement in the cement sheath. For this, more than 50 additives can be added to provide optimum slurry characteristics for severe downhole conditions. For example, the addition of Pozzolan can reduce permeability and reduce corrosion rates by 50% and 70%, respectively, according to an experiment performed by the authors. Salt water usage in Portland cement reduces the corrosion rate up to 10%. Microfine cements with average and maximum particle size of 4–6 and 15 μm can penetrate relatively small fractures [20]. The use of latex cement, which is blends of API Class A, G or H cement with the polymer latex added, can resist acid corrosion and improve the hardened cement’s elasticity and bonding strength of the cement slurry [21,22].
3. Well integrity criteria The well integrity criteria for the wells in CSEGR, either newly drilled wells or existing wells, have to meet the requirements for safe and long-term storage. 3.1. New wells An injection well and production well, is drilled, if necessary, during CSEGR operations to inject supercritical CO2 and produce natural gas accompanied by formation water and CO2, respectively. Although the drilling program for CO2 applications is not different from the conventional ones, the minimization of formation damage is critical so that near wellbore formation does not provide leakage pathways. Experiences have been gathered on the injecting well experience for various CO2 injection projects in and outside USA, and the materials selection for the well components have been summarized. But it is not applicable to every CCS case since the reservoir conditions and the expected purposes of CCS are not always the same [38]. 3.1.1. Casing strings For newly drilled wells, the casing is generally recommended to be set in the middle of the caprock and the liner overlap length should be minimized as well. The nature and magnitude of the downhole corrosive environment in case of high reservoir water saturation or W-A-G (Water Alternating Gas) method of injection, promotes rapid corrosion of casings. The part of casing below the packer is prone to carbonic acid and therefore warrants corrosion resistant alloy. Since the liner is difficult to replace, so the choice for corrosion control in terms of material selection is of paramount importance. Common methods are the usage of corrosion resistant alloys like Duplex stainless steel or lined material such as Glass
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Reinforced Epoxy (GRE), Internal Plastic coating (IPC). But material like IPC may be unsuitable for liners since perforation will cause damage to the integrity of the material, resulting in CO2 entering the lined material and corrosion of exposed metal surface [11]. 3.1.2. Tubing Similarly to casing strings, the part of tubing below the packer suffers corrosion severely and this part of tubing must be made of corrosion resistant alloys. In case of CO2 stream contaminated by H2S, it is found that injection tubing made of seamless L-80 material with Hydfil CS premium connections can prevent Sulfide Stress Cracking (SSC). Also larger diameter tubing will facilitate installation of a larger size of Wireline Retrieved Surface Controlled Subsurface Valve (WRSCSSV) as well as future coiled tubing workover. Composite lined material like Glass Reinforced Epoxy (GRE) linings, Internal Plastic Coatings (IPC), thermoplastic coatings such as High Density Polyethylene (HDPE) and Polyvinyl Chloride (PVC) are more commonly used as corrosion barriers for injection tubing [23]. The use of corrosion inhibitors can be made along with corrosion resistant alloy tubing, to prolong the tubing life. Although it does not prevent corrosion, it can reduce it to an acceptable level before workover is made.
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increase CO2 pressure to the required injection pressure and it is equipped with suction scrubbers and discharge cooler for each of the four compression stages [21]. The suction scrubbers remove traces of liquids in the stream and the coolers remove heat generated in compression. For the material of the construction of coolers, downstream piping, vessels and other equipments, stainless steel is recommended. The production well for CSEGR includes the surface equipment much as the conventional oil and gas wells. According to a scientific report about failures of completion components of production wells by the Sheep Mountain Unit (SMU), wing valve replacement was 52% while master valve replacement was 28%. So they must be given more consideration when designing a production well [24]. 3.2. Existing wells
3.1.3. Packer The location of a packer, whether the completion components or casing is above or below it, provides a reference for material selections, and also assists in risk assessment. The production packer elements should be chemically inert to the CO2 and H2S environment at high temperatures prevalent downhole, and the packer body should be made of corrosion resistant alloys, so that they can have a long service life in hostile corrosive conditions. For the packers used in Jedney Field in Canada for disposal of acid gas, the inner mandrels and packer bodies were made of Incoloy. The packer elements were specially formulated source of spec nitrile rubber while the seal assemblies were made of AFLAS acid resistant materials [21]. The packer fluid to be selected should be resistant to acidic waters as well.
3.2.1. Operational wells The existing operational wells to be used in CSEGR for either injection or production purposes, shown in Fig. 3(a), are confronted with more constraints in comparison with new wells. To select an appropriate well for CSEGR operations one has to consider whether the well is currently used for injection or production. This consideration confirms the availability of necessary infrastructure such as injection or production surface facilities, well head and other associated completions. Favorable presence of the above components reduces the cost of replacing components or workover. However, the casing size, in some cases, might limit the completion options and well interventions. Secondly, water injection wells, which are known to suffer from corrosion and erosion due to high water velocity during injection, might be unsuitable for CSEGR. Last but not least, CSEGR warrants injection of CO2 below a certain depth with consideration to factors such as cap rock location, saline aquifer location, and geomechanical issues, depending upon the reservoir conditions, geology and storage mechanism of CO2, so it is important to determine whether the required depth of injection is above or below the cased depth.
3.1.4. Well completion The injected CO2 is compressed through multi-stage compressors accompanied by liquid removal and dehydration in every stage to prevent the formation of corrosive carbonic acid. A fourstage centrifugal or reciprocating compressor system is used to
3.2.2. Abandoned wells When a well is no longer needed, it has to be plugged and abandoned according to local mining regulations and guidelines. The typical procedures to abandon a well in Germany involve firstly shut off the connection to the reservoir using a bottom
Fig. 3. (a) Operational well structure (b) plugged and abandoned well [8].
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cementation. Additional cement plugs are placed where potential problem zones are, e.g., above the liner, in combination with mechanical plugs, if necessary. Heavy drilling fluid with Bentonite added is filled into the space in between these plugs. In the near surface, the casings are cut a length of minimum 1 m for onshore wells and 5 m for offshore wells and covered by a cement plate or a steel plate, as shown in Fig. 3(b) [7]. The well integrity criteria for abandoned wells are inherently different from operational wells because the abandoned wells being out of service are not subjected to any type of monitoring activities. Also the geomechanical changes in the near wellbore region are unknown since the abandonment of the well. The residual strength of the material will be a decisive factor to decide whether the casing will maintain the well integrity or not. The state of the casing in terms of the mechanical integrity and corrosion should be investigated. Since the data available does not suffice for a direct assessment, some indirect methods such as risk assessment are used [2,25,26]. More explanation can be found in the following section of this paper.
condition. Identification of channels in cement and tubular damage is possible, thereby revealing the status of zonal isolation for remedial work. Cement Bond Log (CBL) is often used to evaluate the quality of primary cementation job by giving the compressive strength of the cement and Bond Index (BI). The CBL readings are affected by casing size, casing thickness and borehole fluids. However, in absence of Variable Density Log (VDL) and transit time (TT), CBL alone cannot indicate cementation problems such as channeling, micro-annulus and bonds between interfaces and so on. In addition to above mentioned tests, there are also some other methods to investigate the well conditions, e.g., noise log, production logging, oxygen activation method, isolation scanner, ultrasonic casing imager and so on. Table 1 shows the strengths and weaknesses of the Schlumberger tools CBL, USIT und Isolation Scanner. It can be seen that logging tools have advanced to the point that they can identify and characterize most defect which can provide pathways for liquids and gases [8].
4. Determination of well integrity for operational wells
5. Risk based approaches for abandoned wells
Migration of the injected CO2 along the wellbores should be monitored to avoid unacceptable leakage. The variety of monitoring techniques can be grouped into several families, each one having its own range application [39]. Examples are Standard Annulus Pressure Test (SAPT), Radioactive Tracer Survey (RATS), Temperature Log (TL), Ultra Sonic Imager (USI), Ultrasonic Casing Imager (UCI), Cement Bond Log (CBL) and so on [27,28]. The SAPT test relies on the principle that pressure applied to a closed system, e.g., annulus between casing and cement, will be maintained if there are no leaks in the system, even if the pressure source is removed. It is easy to interpret, and inexpensive to perform. However, it is unable to detect bad primary cement jobs, or leakage by-passing the shoe. RATS involves addition of radioactive (RA) tracers to the injected fluid and then with the RA detector which is run on wire line to detect the tracers. It is expensive, and difficult to handle radioactive materials. Temperature Log is a record of temperature gradient of a well with geothermal gradient as a reference, taken before production or recorded when well is shut-in. Interpretation is done by looking for anomalies or departures from reference gradient, which are related to entry of fluids in borehole or exit in the formation. Interpretation of temperature log is difficult and requires high expertize. USI gives an accurate and high-resolution, real-time information about pipe-to-cement bond quality and downhole pipe
5.1. FEP (Features, Events and Processes) based method
Table 1 Wireline tool comparison for characterization of leakage pathways [8].
Structured methods have been developed and successfully applied to evaluate the technical integrity of a repository for radioactive waste. The expertize has been transferred to well integrity evaluation in CCS applications [2,29]. The method comprises two steps, which are scenario development and consequence analysis. The Features, Events, and Processes (FEPs) are essentially all activities influencing the storage of CO2 in the long term. Scenarios describe the possible future developments of a system under consideration, defined by a combination of Features, Events, and Processes (FEPS). The developed scenarios are evaluated in the context of consequence analyses. Based on the pilot area, the authors have started from the Quintessa FEP database, which is a generic data base to describe the behavior of the storage system. It has totally 178 FEPs which are categorized as 8 different groups. After screening and supplement of the FEP database, a new case-specific FEP database was obtained to comprehensively describe the storage system. Obviously, FEPs database is only a qualitative way of describing the static characteristics and dynamic performances of a storage system, and it cannot provide a quantitative evaluation. It can be seen as a reference book or an initial help in the early phase of a storage project and provides the basis for modeling [7].
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A Performance and Risk Management (P&R™) method was developed by some researchers and companies [30–32]. This method covers data collection, static and dynamic model development, numerical leakage simulation, risk mapping. The first step of this method is to collect all data and information about the storage system. After that a static model is built, which acts an input into a dynamic model. The core of the dynamic model is a well completion and leakage simulator Simeo™-Stor, which can numerically predict the CO2 leakage along the wellbore over time. Since the data is mostly uncertain, or even not adequate, a risk assessment is often performed which can take the uncertainties into consideration. However, the lack of data for plugged and abandoned wells needs too many assumptions, which leads to a very uncertain evaluation [7]. CO2-PENS (CO2-Predicting Engineered Natural System) is a probabilistic simulation tool designed to incorporate CO2 injection and sequestration knowledge from the petroleum industry to perform risk assessment [33–36]. The model links high level system models (reservoir model) to the process level (wellbore leakage, chemical interaction of CO2) and thus represents a hybrid coupled process and system designed to simulate different CO2 pathways. Simulation of wellbore leakage is complicated since the associated interactions and processes are not yet entirely understood. 5.2. A new concept for well integrity evaluation A comprehensive assessment method was developed with the application in the Altmark natural gas field in Germany [2,25]. It describes the whole near wellbore zone and quantitatively simulates the critical events and processes which influence well integrity and estimate the long-term leakage rate within the storage period. The process of the method comprises three steps which are FEPs (Features, Events and Processes) and scenario analysis, model development and consequence analysis, as shown in Fig. 4. An analysis of FEPs provides an excellent basis for the definition of scenarios which are evaluated in the next step model development. The first model is mechanical integrity model which aims to evaluate the mechanical integrity of the wellbore and provide a quantitative characterization of the defects in the casing–cement–rock composite system, which is then used to estimate the permeability of the casing–cement–rock composite system. A numerical model will be developed to describe the processes and events considered in a scenario in abstract form, so that the leakage rate over a certain time frame can be simulated. In comparison to above-mentioned methods, the proposed method in this paper covers both qualitative and quantitative
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analysis. The goal is to reach a sound risk analysis for well integrity coupling both a thorough FEPs analysis and quantification of the leakage risk of CO2 along a defected wellbore under a series of mechanical and geochemical processes.
6. Conclusions To ensure a meaningful storage of CO2, well integrity of operational and abandoned wells have to be evaluated prior to injection. Many individuals have committed much effort to investigate related issues such as loss of well integrity, well integrity criteria for new and existing wells, as well as well integrity inspection and evaluation. By analyzing the field data and literatures, it is found that mechanical loading and chemical corrosion of cement and tubular are the two aspects resulting in loss of well integrity. As such, materials selection for newly drilled wells or plugging a well has been investigated as well to achieve well integrity for safe operation and storage in CSEGR. Assessment of well integrity for both operational and abandoned wells can be performed in different ways. For operational wells, different tests can be implemented with varying accuracy. However, no logging tool is available which can explicitly detect the presence and extent of corrosion in cement. A commonly used one is CBL complimented with Variable Density Log (VDL) to identify different defects such as channeling, micro-annulus and debonding. For abandoned wells, only indirect risk based method can be used, for example, FEP based method, Performance and Risk (P&R™), CO2-PENS and so on. A new concept has been introduced which couples FEPs analysis, model development and CO2 leakage simulation and consequence analysis. If an application of this method results in a low leakage risk, no further action is required. Medium risks should result in monitoring activities, while high risk wells require reopening and re-plugging. In future, more efforts are required to extend the research on well integrity evaluation of plugged and abandoned wells. Cement based materials are reactive porous media. When exposed to acidic environment, some dissolution/precipitation processes can occur and lead to mechanical and transport properties modifications. The coupled geo-chemical and geo-mechanical effects on cement properties should also be included into a future model. Although a novel and comprehensive methodology has been described in this work, it needs laboratory experiments or field data to verify the results, for instance, the mechanical integrity and the characterization of the defects in the casing–cement–rock composite system, or the self-healing effect of salt rock on the well integrity.
Model Development
Consequence Analysis
Site - specific FEPs Database development
Interaction Matrix between sys. components
Mechanical model development
Selection of most important sys. components
Chemical model development
Scenarios formation
Leakage model development Fig. 4. Flow chart of well integrity evaluation.
Decision making
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Acknowledgments This work is supported by the PetroChina Innovation Foundation (Grant no.: 2015D-5006-0202), Graduate Education Innovation Project in Heilongjiang Province (Grant no.: JGXM_HLJ_2014027), Heilongjiang Postdoctoral Grant (Title: Investigation of the THMC Coupling Effect on CO2 Migration along Casing–cement–rock Composite System), and Technology Project for Returned Oversea Scholars in Heilongjiang Province (2014, Mingxing Bai).
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