DESIGN AND MECHANICAL INTEGRITY OF CO2 INJECTION WELLS/KONSTRUKCIJA I MEHANICKA CJELOVITOST BUSOTINA ZA UTISKIVANJE CO2

Abstract

Geologic Sequestration (GS) is part of a process known as "carbon capture and storage (CCS)" and represents the process of injecting CO2 into deep subsurface rock formations for long-term storage. For injecting of CO2 existing wells are used as well as new drilled wells. A well represents the most likely route for leakage of C02 from geologic carbon sequestration. Maintaining mechanical integrity helps prevent the well and wellbore from becoming conduits for CO2 migration out of the injection zone. The typical components of a CO2 injection well are casing, tubing, cement, and packer. These components are relevant for maintaining mechanical integrity and ensuring CO2 does not migrate upwards from the injection zone into underground source of drinking water (USDW); therefore helping to ensure zonal isolation of the injected carbon dioxide. In order to have the safe underground storage of CO2 well integrity considerations should be present during all phases of well life including design phase, drilling, completion, injection, workover (service) and abandonment. The paper describes well design, well integrity and mechanical integrity tests (MITs) as a means of measuring the adequacy of the construction of the injection well and as a way to detect problems within the well system. [PUBLICATION ABSTRACT]

Headnote

Key words: carbon capture and storage (CCS), injection well, CO2 injection, leakage, mechanical integrity

Abstract

Geologic Sequestration (GS) is part of a process known as "carbon capture and storage (CCS)" and represents the process of injecting CO2 into deep subsurface rock formations for long-term storage. For injecting of CO2 existing wells are used as well as new drilled wells. A well represents the most likely route for leakage of C02 from geologic carbon sequestration. Maintaining mechanical integrity helps prevent the well and wellbore from becoming conduits for CO2 migration out of the injection zone. The typical components of a CO2 injection well are casing, tubing, cement, and packer. These components are relevant for maintaining mechanical integrity and ensuring CO2 does not migrate upwards from the injection zone into underground source of drinking water (USDW); therefore helping to ensure zonal isolation of the injected carbon dioxide. In order to have the safe underground storage of CO2 well integrity considerations should be present during all phases of well life including design phase, drilling, completion, injection, workover (service) and abandonment.

The paper describes well design, well integrity and mechanical integrity tests (MITs) as a means of measuring the adequacy of the construction of the injection well and as a way to detect problems within the well system.

Kljucne rijeci: hvatanje i geolosko uskladistenje ugljika (CS), utisna busotina, utiskivanje CO2, propustanje, mehanicka cjelovitost

Sazetak

Geolosko skladistenje (GS) kao dio procesa "kaptiranje i skladistenje ugljicnog dioksida (CS)" predstavlja proces utiskivanja CO2 u duboko zalijezuce stijene radi trajnog skladistenja. U tu svrhu koriste se postojece busotine, ali se izraduju i nove busotine. Busotina predstavlja najvjerojatniji put za migraciju CO2 iz stijena u kojima je on uskladisten. Odrzavanjem mehanickog integriteta busotine onemo-gucava se da busotina i njen prstenasti prostor postanu putovi migracije CO2 iz utisne zone prema povrsini. Osnovne komponente busotine za utiskivanje CO2 su: kolona zastitnih cijevi, tubing, cementni kamen i paker. Ove komponente su bitne za odrzavanje mehanickog integriteta i sprjecavanje vertikalne migracije CO2 iz utisne zone u stijene koje sadrze pitku vodu (USDW) jer pomazu da se izolira zona (naslage stijena) u koju je ugljicni dioksid utisnut. Radi postizanja sigurnog uskladistenja radnom vijeku busotine od planiranja, preko busenja, opremanja, utiski-vanja, odrzavanja (remonta) sve do trajnog napustanja busotine.

U radu se opisuju konstrukcija utisne busotine, cjelovitost busotine te navode testovi mehanickog integriteta (MITs) kojima se odreduje da li je primijenjena odgovarajuca konstrukcija utisne busotine i otkrivaju problemi unutar kanala busotine.

Introduction

The interest in carbon capture and storage is relatively new, but the underground injection and effective storage of large quantities of CO2 is not a new technology for oil and gas industry. In the last 10 years, most of the technologies developed through the last 44 years of CO2 EOR (enhanced oil recovery) experience have been successfully applied in GS (geologic sequestration) for CCS (carbon capture and storage) in saline aquifers Sweatman et al., 2009)

To date, the technology as a whole has only been de-ployed so far at a few pilot sites around the world such as the Sleipner field in Norway, Weyburn field in Canada, In Salah field in Algeria (Gallo et al, 2002, Jimenez and Chalaturnyk, 2002). The majority of locations that are being considered for carbon dioxide (CO2) injection and sequestration are typically found in the areas that have a history of oil, natural gas, and/or coalbed methane produc-tion (Ennis-King and Paterson, 2002; Gallo et al, 2002; Bellarby, 2009). Due to well logging and exploration ac-tivities in these regions, there is also a greater knowledge base for saline formations that lie either above or below oil and gas reservoirs.

For the EOR operations, thousands of injection wells have been successfully constructed and operated by numerous oil and gas companies in many different oil fields in the world. Unlike Croatia, in the United States injection wells are classified into five class, authorized under the Safe Drinking Water Act (SDWA), and regulated under the Underground Injection Control (UIC) Program. CO2 is being injected in the U.S. under two well classifications: Class II and Class V experimental technology wells. In December 2010 the US EPA finalized regulations for a new class of injection well - Class VI well for geologic storage of CO2 and established a path for commercial geologic carbon sequestration US EPA, 2010 and 2011).

In Croatia, there are favourable natural conditions for geological storage of carbon dioxide - in the deep structural depressions of the southern Pannonian basin, and in the Adriatic off-shore as well (Saftic et al. , 2008). The most prospective objects in the near future are depleted hydrocarbon fields. In Ivanic oil field in the Sava depression, the pilot CO2 injection has already been done as a part of an EOR project not for purpose of geologic storage.

The carbon dioxide injection is different than injection of other fluids because carbon dioxide is less dense than most subsurface fluids. It is buoyant and will tend to migrate to the top of the injection zone. Carbon dioxide also has the potential to be corrosive when mixed with water. The well needs tomaintain its integrity for the life of the project since the goal of GS is the long term storage of carbon dioxide. An improperly constructed well can lead to loss of well integrity that could lead to carbon dioxide or formation fluid leakage from the wellbore and into USDWs (Gasda et al., 2004 and 2005).

C02 injection well design

The technologies for drilling and completing CO2 injection wells are well developed. American Petroleum Institute published a number of Specification and Recommended Practices for Casing and T ubing, and Well Cements such as:14PI Specification 5CT - Specification for Casing and Tubing, API RP 5C1 - Recommended Practices for Care and Use of Casing and Tubing, API RP 10B-2 - Recommended Practice for Testing Well Cements, API Specification 10A - Specification on Cements and Materials for Well Cementing, API RP 10D-2 - RecommendedPractice for Centralizer Placement and Stop Collar Testing, and API Specification 11D1 - Packers and Bridge Plugs.

Most aspects of drilling and completing such wells are similar or identical to that of drilling and completing a conventional gas or other) injection well or a gas storage well, with the exception that much of the downhole equipment (e.g. casing and tubing, safety valves, cements, blowout preventers) must be upgraded for high pressure and corrosion resistance. The well is completed at the surface by installing a wellhead and "Christmas Tree" that sits on top of the wellhead and is an assembly of valves, pressure gauges and chokes. Devices are connected to the "Christmas Tree" that allow the monitoring of pressure, temperature, and injection rates (Figure 1). The combined wellhead has casing annulus valves toaccess all annular spaces to measure the pressure between the casing strings and between the casing and production tubular. Above the Christmas tree a CO2 injection valve is mounted and an access valve for running wirelines from the top.

The typical components of an injection well that are relevant to maintaining mechanical integrity and to ensuring that fluids do not migrate from the injection zone into USDWs are the casing, tubing, cement, and packer (Figure 2). The well components should be designed to withstand the maximum anticipated stress in each direction - axial direction (tensile, compressive) or radial (collapse, burst), and include a safety factor. The loading in each of the stress directions should be compared to the strength of the material in that direction. The loadings correspond to the burst, collapse, and tensile strengths of the material.

Casing

An injection well typically consists of one or more casings. Leaks in the casing can allow fluid to escape into unintended zones or allow fluid movement between zones. The construction materials selected for the casing and the casing design must be appropriate for the fluids and stresses encountered at the site-specific down-hole environment. Carbon dioxide in combination with water forms carbonic acid, which is corrosive to many materials. Native fluids can also contain corrosive elements such as brines and hydrogen sulfide. In C02 injection wells, the spaces between the long string casing and the intermediate casing, and between the intermediate casing and the surface casing as well as between the casings and the geologic formation are required to be filled with cement, along all casings.

Tubing

The tubing runs inside the long string casing from the ground surfacedown to the injection zone. The injected fluid moves down the tubing, out through the perforations in the long string casing, and into the injection zone. The tubing ends at a point just below the packer. The space between the long string casing and tubing must be filled with a non-corrosive packer fluid. The tubing forms another barrier between the injected fluid and the long string casing. It must bedesigned to withstand the stresses and fluids with which it will come into contact. The tubing and long string casing act together to form two levels of protection between the carbon dioxide stream and the geologic formations above the injection zone. A safety valve/profile nipple can be used to isolate the wellbore from the formation to allow the tubing string to be replaced. Injection will be conducted through the perforated casing. In the base case there is no stimulation method used, but hydro fracturing may be an option. Using acids to improve injectivity is not recommended because of the possible damage to the cement sheath and casing.

Cement

Cement is important for providing structural support of the casing, preventing contact of the casing with corrosive formation fluids, and preventing vertical movement of carbon dioxide. Some of the most current researches indicate that a good cement job is one of the key factors in effective zonal isolation. The proper placement of the cement is critical, as errors can be difficult to fix later on. Failing to cement the entire length of casing, failure of the cement to bond with the casing or formation, not centralizing the casing during cementing, cracking, and alteration of the cement can all allow migration of fluids along the wellbore. If carbon dioxide escapes the injection zone through the wellbore because of a failed cement job, the injection process must be interrupted to perform costly remedial cementing treatments. In a worst case scenario, failure of the cement sheath can result in the total loss of a well. During the injection phase, cement will only encounter CO2 However after the injection phase and all the free CO2 around the wellbore is dissolved in the brine, the wellbore will be attacked by carbonic acid H2CO3). The carbonic acid will only attack the reservoir portion of the production casing, therefore special consideration of CO2 cement needs only to be considered for the reservoir, primary seal and a safety zone above the reservoir. Regular cement should be sufficient over the CO2-resistant cement. However since two different cement slurries will be used, CO2-resistant cement that is compatible with regular Portland cement has to be used to prevent flash setting. The cement must be able to maintain a low permeability over lengthy exposure to reservoir conditions in a CO2 injection and storage scenario. Long-term carbon sequestration conditions include contact of set cement with supercritical CO2 (>31 °C at 73 bars) and brine solutions at increased pressure and temperature and decreased pH (Kutchko et al, 2007).

Packer

A packer is a sealing device which keeps fluid from migrating from the injection zone into the annulus between the long string casing and tubing. The tubing is set on a retrievable packer above the injection zone to ease the changing of the tubing if pitting is identified during regular inspections. A packer must also be made of materials that are compatible with fluids which it will come into contact.

Design requirements

All new CO2 injection wells have to be cased and cemented to prevent the migration of fluids into or between underground sources of drinking water. The casing and cement used in the construction of each newly drilled well has to be designed for the life expectancy of the well. In determining and specifying casing and cementing requirements, the following factors has to be considered: (1) depth to the injection zone; (2) injection pressure, external pressure, internal pressure, axial loading, etc.; (3) hole size; (4) size and grade of all casing strings (wall thickness, diameter, nominal weight, length, joint specification, and construction material); (5) corrosiveness of injected fluids and formation fluids; (6) lithology of injection and confining zones; and (7) type and grade of cement. The following information concerning the injection zone has to be determined or calculated for new wells: (1) fluid pressure; (2) fracture pressure; and (3) physical and chemical characteristics of the formation fluids. Appropriate logs and other tests have to be conducted during the drilling and construction of new wells. Mandatory technical requirements for CO2 injection well kre presented in Table 1.

Degradation of wellbore cement due to C02 injection

Portland cement systems are used conventionally for zonal isolation in oil or gas production wells. The properties of Portland cement are determined by the mineralogical composition of the clinker. When Portland cement is mixed with water, its compounds form hydration products. The main products formed by the cement hydration process are calcium silicate hydrate gel - CSH and calcium hydroxide - Ca(OH)2 CSH is a semi-amorphous gel-like material that compromises approximately 70 wt % of the hydrated cement and is the primary binding material. Portland cement is thermodynamically unstable in CO rrich environments and can degrade rapidly upon exposure to CO2 in the presence of water. As CO2-laden water diffuses into the cement matrix, the dissociated acid (H2CO3) reacts with the free calcium hydroxide and the calcium-silicate-hydrate gel. The reaction products are soluble and migrate out of the cement matrix. Eventually, the compressive strength of the set cement decreases and the permeability and porosity increase, leading to loss of zonal isolation (Gaurina-Medimurec, 2010). There are mainly three different chemical reactions involved in cement-CO2 interaction shown in table 2 Onan,1984; Bellarby, 2009; Santra et al., 2009).

CO2 diffuses into the capillary pores of the cement which contain, to some extent, water and dissolves in it to form carbonic acid (Eq. 1).Forming of carbonic acid causes lowering in pH value, depending on temperature, partial pressure of CO2, and other ions present in water, such as salt, etc. Carbonic acid reacts with calcium hydroxide (also named as hydrated lime or portlandite) in the cement causing carbonation of Ca(OH)2 (Eq. 2a) and/or decomposition of calcium silicate hydrate gel, the main binding component in hydrated cement, into calcium carbonate and an amorphous silica (Eq. 2b). The carbonation reactions will cause densification, leading to increased hardness and reduced permeability thereby decreasing CO2 diffusion and up to 6% volume expansion, which can lead to development of micro to macro cracks in extreme cases. This carbonation reaction d issolves and weakens the cement making it liable to ultimately leak. The rate at which cement d egradation occurs depends primarily on temperature, but also on cement type, cement composition, water/cement ratio, moisture content, CO 2 partial pressure, and porosity/permeability (Kutchko et al, 2007, Santra et al, 2009). Carbonation is extremely fast in the early days but later slows down drastically because of the time dependant reduced porosity/permeability caused by the initial carbonation itself (San tra et al., 2009). Dissolution of CaCO is a long-term phenomenon and happens only when the set cement is surrounded by liquid water containing d issolved CO2 Eq. 3). Effects of this reaction are increased porosity/ permeability and loss of overall mechanical integrity, leading to inefficient or even potential loss of zonal isolation in extreme cases. Several approaches have been adopted to help reduce detrimental effects of carbonation Santra et al., 2009): (a) red uce the amount of Portland cement by incorporating filler, (b) reduce porosity/ permeability, (c) add reactive supplementary materials to red uce the Ca(OH)2, as well as changing the CSH composition to a more CO2-resistant one.

Mechanical integrity

Mechanical integrity is a key concept related to the performance of an injection well, and the prevention of injected fluid movement into or between USDWs or other zones. Mechanical integrity of the well is achieved by ensuring that each of the components of the well are constructed with appropriate materials and are functioning together as intended. Typical corrosion resistant materials include 316 stainless steel, fiberglass, or lined carbon steel for casing and tubing. Casing and tubing can be lined with glass reinforced epoxy, plastic, or cement. If lined casing or tubing is used, care is recommendedduring installation to avoid damaging the lining (Meyer, 2007). Other metal parts such as packers and valves can be nickel plated or made of other high nickel alloys (Table 3).

Several potential leakage pathways can occur along active injection well (Figure 3a) and/or abandoned well Figure 3b). These include leakage: through deterioration (corrosion) of the tubing (1), around packer (2), through deterioration (corrosion) of the casing (3), between the outside of the casing and the cement (4), through deterioration of the cement in the annulus (cement fractures) (5), leakage in the annular region between the cement and the formation (6), through the cement plug (7), and between the cement and the inside of the casing (8).

Maintaining mechanical integrity helps prevent the well and wellbore from becoming conduits for fluid migration out of the injection zone. There are two aspects of mechanical integrity: internal and external.

Internal mechanical integrity

Internal mechanical integrity is denned as the absence of significant leaks in the casing, tubing, or packer. These well components act as the main barriers preventing contact between the injected carbon dioxide stream and the surrounding geologic formations through which the well has been drilled and constructed. Ensuring that these components are constructed properly with appropriate materials and that they remain undamaged when subject to stresses or corrosive (and other) operational conditions may prevent carbon dioxide from moving out of the well bore during injection (NETL, 2009). The pressure applied during an internal mechanical integrity test should be limited to prevent casing ballooning that could create cement defects.

The absence of significant leaks in the casing, tubing, or packer is demonstrated through the use of (1) the standard annulus pressure test (SAPT), (2) the standard annulus monitoring test (SAMT), and (3) the radioactive tracer survey (RTS).

External mechanical integrity

External mechanical integrity is denned as the absence of significant leakage outside of the casing. Maintaining external mechanical integrity helps to ensure that the injected carbon dioxide, which tends to be more buoyant than native formation fluids, does not migrate upwards from the injection zone after it has been injected; therefore helping to ensure zonal isolation of the injected carbon dioxide. The main construction component ensuring external mechanical integrity is the set cement. Properly emplaced cement should both prevent fluid movement by sealing the space between the casing and the formation, and protect the well casing from stress and corrosion.

The absence of significant fluid movement into an USDW through vertical channels adjacent to the injection well bore is demonstrated through the use of (1) the results of a temperature log, (2) noise log, (3) oxygen activation log (OAL), (4) the results of a radioactive tracer survey (RTS) (when the injection zone is separated from the lowermost USDW by a single confining layer), or (5) cementing records (Ultrasonic well logging; Cement bond log - CBL) demonstrating the presence of adequate cement to prevent fluid migration into USDWs.

Conclusion

In order to have the safe underground storage of carbon, the injection wells as well as any well penetrating through the cap rock have to maintain sufficient integrity over a long time period. Well integrity considerations should be present during all phases of well life including design phase, drilling, completion, injection, workover (service) and abandonment. Both existing and new wells must be fully evaluated and tested for integrity because there are many different possible leakage pathways. It is necessary to examine the condition of the casing and the cement and identify any annuli or defects that exist within the well. There is no one tool or method capable of looking at all of these features at the same time, so a suite of measurements must be run to analyze the integrity of a well. These measurements can be acquired using wireline tools such as caliper and ultrasonic tools to measure the integrity ofthe casing, sonicand ultrasonic tools to measure the integrity of the well cement, and tools to sample the casing, cement, formation, and formation fluid. The choice of well equipment and materials must be carefully consid ered to achieve the desired integrity. CO2 corrosion may be limited by: the selection of high alloy chromium steels, resistant to corrosion, andby inhibitor injection, if using carbon steel casing. In addition use of acid resistant cement is highly recommended.

Accepted: 15.10.2011.

Received: 04.10.2011.

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