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Global warming is one of the most significant issues the world is facing. Capturing carbon dioxide from the atmosphere or industrial processes and storing it in geological formations (carbon capture and storage, CCS) can help counteract climate change. Nevertheless, the interaction between well barrier elements such as cement, casing, tubulars, packers, and valves can lead to possible leakages. To accomplish successful carbon dioxide sequestration, injecting the carbon dioxide in its supercritical state is necessary. The supercritical carbon dioxide can corrode steel and elastomers and react with the calcium compounds in the cement, dissolving them and forming calcium carbonate and bicarbonate in the process. This carbonation can lead to channels forming on the cement-to-rock interface or cracking due to the carbonate precipitation, resulting in a loss of well integrity. This study focusses on finding ways that enable the continuous monitoring of cement integrity, under in-situ conditions, in a lab setup. The construction of an autoclave, capable of withstanding supercritical conditions of carbon dioxide, facilitates the in-situ monitoring. This autoclave also makes CT-scans of the pressurized sample possible, as well as acoustic measurements, using state-of-the-art piezo elements. The first tests will establish a baseline using neat Class G Portland cement to verify the design and sensors. The set up consists of a rock core in the middle of the autoclave surrounded by a cement sheath. A prepared channel in the center of the core expedites the distribution of the carbon dioxide. Once the ability of the sensors to monitor the integrity is verified, different cement compositions and their interaction with supercritical carbon dioxide can be studied. The experimental setup and the procedure discussed here closely simulate the downhole condition. Hence, the results obtained using this setup and procedure is representative of what could be observed downhole. The direction is not to remove the sample from the autoclave for analysis, as is the current industry practice, but to measure cement integrity under in-situ conditions over an extended period of time. Digitalization is powering the in-situ analysis in these tests. The first two tests of this study, using the afore mentioned autoclave, investigated the carbonation behaviour of two Class G Portland cement slurrys, one with a low and one with a high slurry-density. The low-density slurry showed extensive degradation and even the high-density slurry showed carbonation, but only close to the sandstone core. The results from this study can lead to the prevention of leakage of carbon dioxide to the environment and other formations, which defeats the purpose of carbon dioxide sequestration. These results should improve the economics of these wells as well as the health, safety, and environmental aspects.

Well integrity is one of the main issues during all life cycles of the well and if any barrier element fails and compromise the integrity of well, remedial strategy may have to be performed to restore the safety and economics of the well. Cement is conventionally used as the isolation material in remedial and primary jobs. However, due to several inherent limitations in cement characteristics, such as cement shrinkage or poor cement slurry compatibility with downhole fluids, it is not always the best solution. Besides, cement slurry is a particle laden fluid which prevents it penetrating in to tight cracks/pathways to ensure isolation during remedial treatments. This project illustrates the effort to develop a customized polymer system as cement alternative addressing several challenges posed by conventional materials and experimental studies are designed to evaluate its characteristics such as rheology, injectivity and mechanical properties. Furthermore, the compatibility of these systems with drilling fluids contamination and shrinkage behaviour upon cure are evaluated. Afterward, based on the results of measurements, the limitations of each system are determined and the best formulation is optimized. The results of experiments prove that beside the appropriate rheological properties, the system provides excellent mechanical properties and much lower shrinkage rate upon cure compared to cement. The system withstands and maintains its properties after being contaminated with considerable volume of downhole fluids such as drilling fluids and hydrocarbons and mechanical properties such as compressive strength is not much affected by contamination. The unique characteristics of customized sealing system as cement alternative could provide benefits to industry by solving several current challenges in achieving secure isolation. Particularly due its ability to penetrate in to tight cracks, this system affords an effective method to mitigate sustained casing pressure or as a remedial solution for casing leakages which cannot be achieved easily by conventional methods.

Fluid invasion during cement hydration is governed by, among other factors, differential pressure between the formation fluids and the annular fluid. The primary phenomena influencing pressure in the annulus are evolution of cement slurry physical and chemical properties with time, filtrate lost to the formation, and changes in cement slurry volume during hydration. A successful procedure to design slurries to mitigate fluid invasion shall model these phenomena and provide viable methods to measure model parameters. At the same time, it should be feasible to formulate cement slurries to obtain the parameters necessary for a successful design. This paper discusses model details with emphasis on parameters, their test procedures, and equipment details. Dynamic filter-cake properties are calculated by applying compressible filtration theory on data from a modified fluid loss test. Shrinkage/expansion is measured under temperature using the API ring mold apparatus. Pressure and displacement response to filtrate loss and shrinkage/expansion is dependent on bulk modulus, shear modulus, and static gel strength (SGS) evolution of the cement slurry during hydration. Properties are measured as a function of time using sonic analysis and a rotational gel strength device. Both material properties and volume changes attributed to fluid loss and hydration showed time dependency. Furthermore, the pressure response of two realistic wells having different permeability and pore pressure profiles is analyzed. The two analyzed wells had different pressure responses, indicating that the slurry design should be customized for each well. This difference is attributed to varying capabilities of the well to compensate for volume loss by movement of cement placed adjacent to the permeable section, showing that the relative locations of the filtrate loss and potential fluid influx zones are important. Such an observation is possible only because of the ability to measure and model dynamic properties and events. The proposed methods are practical and can be realized using existing equipment with few procedural changes. Analysis based on these measurements guides the customization of slurry designs.

Summary Cement-sheath shrinkage after placing the cement slurry in the annulus has been of concern in oilwell cementing because of the potential detrimental effects that shrinkage can have on long-term zonal isolation. This paper compares several methods for measuring cement shrinkage under a variety of conditions including those downhole. Using the various methods, cement shrinkage in environments where the cement slurry is either closed to or open to external water sources was measured, and the values were compared. The methods used for measurement under atmospheric conditions were based on American Petroleum Institute (API) test apparatus (balloon and ring mold) and flask methods currently used in laboratories. Measurements under pressure were performed using the balloon and ring-mold methods, in-house designed equipment, and commercial equipment. The values obtained by the different methods are discussed. Procedure modifications are proposed for measuring volume changes to cement slurries on the basis of placement time, shear history, and gel-strength development. The results presented in this work can be used to test shrinkage characteristics of cement slurries in the laboratory under downhole conditions and to select a cement system that is fit for purpose.

Summary This paper discusses the tests conducted to determine the mechanical properties and the integrity of the cement sheath when subjected to cyclic loads. In addition, the effects of well operation on cement sheaths of different mechanical properties are analyzed, and the results are discussed. The results clearly demonstrate the importance of both laboratory measurements of cement-sheath mechanical properties and engineering analysis of the effect of well operations on the integrity of the cement sheath. Lower-density cement systems are discussed in this paper, along with how the density was lowered by incorporating conventional additives such as Pozzolanic beads (cenospheres) Hollow glass beads Gas bubbles Water-binding additives Silica fume Fly ash Primary cementing compositions for oilwell applications are becoming increasingly complex and challenging because of the extreme well operating conditions encountered. The stresses exerted on the cement sheath during well operations could be severe enough to damage the cement sheath and negatively affect the safety and the economics of the well. The results discussed in this paper should help operators design a cement sheath that can withstand the stresses from well operations, thus improving the safety and economics of the wells.

Wells often require being drilled through and cemented across salt formations. In many parts of the world, salt sections consist of multiple salt types. These include Halite, Carnallite and Tachyhydrite. The last two salt types could move one hundred times faster than Halite and are chemically reactive. Typically, Carnallite and Tachyhydrite occur as streaks inserted between Halite. In these cases, cement sheath should withstand salt creep loading. Creep load is primarily compressive in cases of single salt types. For intercalated salts, varying creep rates can result in tensile loads, particularly at salt-salt junctions. Presalt exploration in offshore Brazil is an apt example displaying this behavior. In such a scenario, the cement sheath along a longitudinal well section should be analyzed for both tensile and compressive responses. It is well known that tensile strength of conventional cement systems is low, hence there is the need for detailed analysis and action to prevent damage to cement sheath. This work demonstrates cement design procedures by evaluating cement sheath mechanical integrity in intercalated salts. A typical presalt Brazilian well with different lengths of Tachyhydrite, Halite, and Anhydrite sections is used as an example in this work. A creep model for these salts is validated with data from triaxial creep testing. Responses of two cement systems, which are cured and tested, are compared. The analysis accounts for classical well loads during drilling and production etc., along with salt creep loading. This analysis shows that intercalated salts subject cement sheath to a series of tensile and compressive loads whose magnitude depends on the size and relative position of different salts. The salt-salt interface effects dominated the general tenet of increasing creep rate with increasing depth. This kind of detailed design procedure representing intercalated salt zones is the first of its kind known to the authors. Results from this analysis help fortify the importance of considering salt layering patterns during cement design for long term mechanical integrity. The design procedure discussed and presented in this study should help the industry design cement systems to withstand loads across single and intercalated salt zones and maintain well integrity.

Long-term cement sheath integrity is important to maintain wellbore stability and effective zonal isolation. Various factors influence cement sheath integrity, such as effective placement of cement, mechanical and thermal stresses, and interaction with corrosive gases. Corrosive gases are known to chemically attack Portland cement. However, the challenge is designing a cement system that can sustain CO2 and H2S attack. Acid-gas-resistant systems are useful in various applications, including producers and CO2 injector wells. To understand how the cement sheath is affected by prolonged exposure to corrosive gases, detailed studies should be performed at different temperatures and pressure conditions. This paper documents a resilient cement system that was exposed to CO2 and H2S gas environments for a period of three months. For comparison purposes, a neat cement system was used as a reference and tests were conducted at 194 (90°C) and 284°F (140°C). X-ray density profiles obtained using tomography techniques were used to analyze samples. The cement samples responded differently to CO2 and H2S environments. Formation of CaCO3 on exposure to CO2 was evident and was reflected in X-ray density profiles. Conversely, leaching of neat cement was observed on exposure to H2S gas. In both cases, the resilient cement system specially designed for the work described proved to be a better option when compared to neat cement because the destruction was less prominent in the former case.

Cement-sheath integrity is fundamentally important for well integrity and helps to ensure that the asset is operated safely and economically. If the cement sheath is damaged during well operations, it could lead to interzonal communication, annular pressure, and casing damage. Remedial jobs are then necessary to fix the problem and continue well operation. In some cases, it might not be economical to fix the problem, leading to well abandonment.The challenge to cement-sheath integrity is caused by the stresses resulting from change in pressure and temperature during well operation. Examples of wells that could be subjected to changes in pressure and temperature are deepwater, high-pressure high-temperature (HPHT), gas storage, steam injection, and geothermal. Gas storage wells in Italy are addressed in this work. An integrated, intelligent, and interventionless solution has been applied to solve the zonal-isolation challenges in such wells. The well events during the life cycle were integrated into the analysis and a cement sheath was designed and tested so that it was not damaged. Safety considerations were built into the design procedures based on the teachings of designs of other materials. This design procedure helped the cement sheath withstand cyclic loads, which could be significant in gas storage wells.During well operations, if the stresses on the cement sheath exceed the design limits, the cement sheath could be damaged. The initial damage could be in the form of small cracks and micro-annuli. If these damages can be fixed immediately and without intervention, then the formation fluid can be prevented from entering the annulus. Intelligent features were built into the cement sheath so that small cracks and micro-annuli could be automatically sealed if formation fluid enters the annulus.The integrated, intelligent, and interventionless zonal-isolation features of the solution offer a unique opportunity to prevent the annular pressure buildup if the cement sheath inadvertently fails. This solution has been implemented in a number of wells and is described in this work. The job implementation and subsequent results during the life of the wells have been successful. The unique features of the solution discussed and presented in this work is a game-changer and should help the industry solve a pressing problem and operate wells safely and economically.

Cement sheath shrinkage after placing the cement slurry in the annulus has been of concern in oilwell cementing because of the potential detrimental effects that shrinkage can have on long-term zonal isolation. This paper compares several methods for measuring cement shrinkage under a variety of conditions including those downhole. Using the various methods, cement shrinkage in environments where the cement slurry is either closed to or open to external water sources was measured and the values were compared. The methods used for measurement under atmospheric conditions were based on API test apparatus (balloon and ring-mold) and flask methods currently used in field labs. Measurements under pressure and temperature were performed using the ring-mold method, in-house designed equipment, and newly available commercial equipment. The values obtained by the different methods are discussed. Procedure modifications are proposed for measuring volume changes to cement slurries based on placement time, shear history, and gel-strength development. The results presented in this work can be used to test shrinkage characteristics of cement slurries in the lab, under downhole conditions, and to select a cement system that is fit for purpose.

Cementing high-pressure, high-temperature (HPHT) wells poses various challenges not seen at normal well conditions. For instance, the following objectives are critical for HPHT wells: Prevent losses during drilling fluid circulation and cement slurry placement. Displace the drilling fluid and place the cement slurry effectively. Prevent free-water or gas-channel development. Reduce slurry fluid loss. Provide support for the production packers. Decrease compression loads on casing connectors. Prevent damage to cement sheath. Prevent annular gas pressure over the life of the well. The industry is recognizing the interaction between these factors to determine the optimal cement job design for accomplishing these objectives. This paper presents and discusses the engineering analysis to determine the optimum foamed cement sheath properties for integrity during the life of the well at HPHT conditions. Also, this paper compares foamed cement to nonfoamed slurries in achieving these objectives. Other important issues discussed are the performance of nitrogen at HPHT conditions and the rheological properties of the foams. Key issues addressed are the state and solubility of nitrogen under downhole conditions and the integrity of the cement sheath during the life of the well. Thermodynamic solution theory and experimental studies are applied to the former, and finite element analysis is applied to the later. Case examples are presented discussing foamed and conventional operations at near HPHT conditions for some Norwegian, North Sea wells. Cement properties are contrasted for the different foamed and conventional cement slurry properties with respect to: Achieving the HPHT objectives, such as placement efficiency and sheath properties Prejob design to obtain the objectives Job planning and procedures Job execution Logging of foamed cement Post-job evaluation of the cement systems

Managing formation (in)stability should be an integral part of well construction from drilling through cementing and completion operations. Formation (in)stability while drilling has been recognized and is an ongoing study in the petroleum industry. Most of the emphasis in these studies has addressed the interactions between drilling fluids and formations, as well as, the geomechanical aspects. However, if the wellbore is stable at the end of the drilling phase, but the cement and spacer properties are not optimized accordingly, the formation could be destabilized during cementing. Such an event could negate much of the prior effort toward controlling instability. Destabilization could adversely impact the well construction and overall field development throughout the well's lifecycle. As the rock material is removed and replaced by a drilling fluid and subsequently displaced by cementing fluids (spacer and cement slurry), stability of the wellbore should be ensured by applying an adequate net radial support to the formation. The borehole pressure exerted by these fluids can counteract the near-wellbore effective stress concentration created while drilling. If the radial support applied to the formation is inadequate, the stress concentration can exceed the formation compressive strength, leading to borehole collapse. On the other hand, excessive borehole pressure can lead to lost circulation problems if the near-wellbore tangential (circumferential) stress and the formation tensile strength are exceeded. As the formation is exposed to drilling and cementing fluids, the near-wellbore effective stress concentration is altered because of the formation fluid's physicochemical interaction. Such alteration of the effective stresses and formation properties can result in time-dependent stability problems.

One of the main objectives of a primary cement job is to prevent formation fluids from migrating into the annulus. To achieve this objective, the cement sheath should withstand the stresses induced by the various well operations and maintain integrity during the life of the well. However, the majority of the cement design programs in the industry today consider only the slurry properties and do not assess the effect of the mechanical properties of the cement sheath on the final well design. A design procedure has been developed to estimate the risk of cement failure as a function of cement sheath and formation characteristics and well loading. A few examples of well loading are pressure testing, well completion operations, hydraulic fracturing, and hydrocarbon production. The design procedure is based on a finite element analysis and simulates the sequence of events from drilling through cement hydration, well completion, and production operations. The cement failure modes simulated are debonding, cracking, and plastic deformation. The cement is assumed to behave linearly as long as its tensile strength or compressive shear strength are not exceeded. The material modeling adopted for the undamaged cement is a Hookean model bounded by smear cracking in tension and Mohr-Coulomb in the compressive shear. Shrinkage and expansion of the cement are included in the material model. The need to design a fit-for-purpose cement sheath is accentuated by the sustained casing pressure observed on a number of wells after they were put on production and on some HPHT wells after the displacement fluid was changed over to a well-completion fluid. The pressure in the annulus side sometimes results in an inability to continue further operation. Applications are discussed and examples are provided. From the processes reviewed in this paper, one can estimate the risk of failure of various cement systems and select a fit-for-purpose system that will minimize the overall cost. This process should improve the economics of constructing and producing oil and gas wells (cost effective life cycle design) and also improve safety because zonal isolation failures may be reduced.

After a well has been drilled, the drilling fluid should be removed and replaced with either cement and/or completion fluids. For effective zonal isolation and optimum hydrocarbon production during the life of the well, the entire drilling fluid should be removed from the annulus. Cement and completion fluids are sensitive to drilling fluid contamination, and even a thin layer of oil-based drilling fluid could prevent the cement from bonding to the formation and the casing. In addition, for optimum hydrocarbon production, the cement sheath must be able to withstand the stresses throughout the life of the well.1 Several factors affect the success of drilling fluid removal from horizontal annuli. Under static conditions, drilling fluid usually forms a gel structure. Under positive differential pressure, the drilling fluid loses filtrate and forms a filter cake on the formation face. Sometimes the filter cake is mushy and difficult to remove, but the formation fluid can easily flow through it. The successful removal of the gel and mushy filter cake depends on the structures that form and how these structures behave under flow conditions. In addition, casing centralization affects the fluid flow profile in the annulus, which affects gel and filter-cake removal. To investigate the mechanism of drilling fluid removal, we conducted both numerical and experimental studies. In the experimental studies, chemical flushes and spacers were tested for their effectiveness in removing drilling fluid. The experiments showed that annulus cleaning begins around the inner pipe and progresses outward at increasing fluid flow rates. Analytical fluid flow models and full 3D multiphase numerical models allowed us to estimate flow profiles and the success of removing drilling fluid under downhole conditions. The large-scale experiments and analytical/numerical modeling have led to a better understanding of the factors controlling drilling fluid removal from horizontal wellbores.

Recent experience in the field has demonstrated that the mechanical properties of the annular sealant are a critical factor in the success of a well. A demanding operational regime such as High Pressure/High Temperature (HP/HT) and well interventions, e.g. pressure testing stimulation, place high demands on the mechanical design of a candidate sealant. The following steps should be followed to determine the required mechanical properties of such well sealant candidates: The stability of the bore hole should be evaluated prior to placing the sealant in the annulus. The stability is affected by the far field stresses, the weight (s.g.) of the drilling fluid and the mechanical properties of the formation. The integrity of the sealant should be investigated for the operational envelope of the well. Finite Element models were used to determine the influence of wellbore stability aspects and the effects of loading on the integrity of the sealant. The mechanical properties of the sealant considered were elasticity, tensile strength, shear strength and bonding strength. In this way it was possible to examine aspects of non-linear material behavior of the sealant. The following factors were investigated in this study: What are the well parameters and its operating envelope? What are the total stresses on the formation and on the sealant under various HP/HT conditions? Which mechanical properties does the sealant have to possess in order to be able to withstand different types of stress? The study indicated that there is a strong interaction between on the one hand the behavior of the sealant and on the other hand the formation in-situ stresses, the formation properties, the well completion parameters and its operating envelope. Depending on these input conditions, the sealant was observed to behave in one of the following manners. The sealant remained intact without any damage. A micro annulus occurred between sealant and casing/formation. The sealant failed because of either tensile or shear deformation. Calculations were performed for various wellbore stability scenarios, well completion characteristics, well loading envelopes and properties of the sealant. Typical oil well cement slurries, latex slurries, foam cements and cement hybrids were investigated. Typical results from the study are discussed and procedures for field application are given.

SPE Members Abstract This paper presents case histories that demonstrate the utility and economy of monitoring circulatable hole (CH) immediately before a primary cement job, and then taking real-time action to correct any deficiencies detected. Although it is well established that effective hole-cleaning is critical to the success of a cementing job, a reliable method has only recently been made available for continuously monitoring the volume of the casing-to-wellbore annulus. Accurately determining the annular volume involved in the circulation process is the key to verifying that the hole is clean. Traditionally, operators have circulated the annulus for an arbitrary length of time; CH monitoring, however, has allowed for accurate assessment of hole condition with as much as 75% less circulation time before cementing. The case histories presented describe methods used to correct CH deficiencies once they are established. These methods include–Pumping at higher rates–Rotating and/or reciprocating pipe–Adding spacers/flushes to the mud system Based on the case histories presented, the following benefits can be derived from the new measurement method:–Circulation times originally averaging 2 hours may be reduced to as little as 30 minutes.–Pipe movement can contribute greatly to the amount of CH.–Operators can save the expense of certain casing equipment traditionally used to increase CH since they know 100% of the annulus is in circulation. Introduction After several years of test studies, the industry has, to some extent, solved the problem of drilling fluid displacement from the annulus between the casing and borehole, by cement and other fluids. Although studies have shown how important nearly full displacement of the drilling fluid is to provide a long-term seal of the annulus, different theories exist about the most effective way to accomplish near-100% displacement. The main difference in these theories is the means by which to increase the shear stress on the static annular fluid by the dynamic annular fluid. P. 271

Abstract To date, the means of efficiently dealing with annular gas migration by way of cement slurry design has been unstructured In approach. The major tools still relied upon are past experiences and a basic knowledge of gas migration past experiences and a basic knowledge of gas migration theory. Although an accepted procedure for determining a well's potential to flow is available, research has not been heavily conducted relating gas flow potential to a specific cement slurry performance required to achieve a predictable success. Instead, "types" of cements cow fluid loss, thixotropic, etc.) are recommended in relation to the degree of flow potential that may be encountered in a well. In response to this deficiency, a method was recently developed and published by Sutton and Rovi. Labeled the Slurry Response Number, SRN, this engineering tool defines the capability of a specific cementing system to combat gas migration in a specific gas well. It is the purpose of this paper to show - through several case histories - that this derived relationship does exist, and can be used to more efficiently design anti-gas migration slurries. More specifically, the field cases observed in this study display a relationship between the Gas Flow Potential (GFP) a mathematical term indicating the probability of gas flow given a set of cement job conditions - and the more recently developed SRN. As reported by Sutton and Ravi, the SRN is a number attached to a specific cementing system (cement, spacer, and drilling fluid), based on fluid loss and static gel strength properties, that directly grades the capability of a cement slurry to prevent gas migration. This unique rating system can be used very effectively for relative comparisons between cement slurries or as confirmed through the case histories presented in this text, con serve as a guideline in choosing a cement slurry design for a specific well with a calculated gas flow potential. Introduction In response to the detrimental results produced by gas migration following a primary cement job, research has increased tremendously over recent years, successfully delivering new technologies to combat this menacing problem. Among the increasing number of innovations problem. Among the increasing number of innovations developed for this prime purpose are new low fluid loss additives, delayed gelling agents 3 latex materials, and compressible cements. While these technologies have proven beneficial in gas problem wells, major pieces of this proven beneficial in gas problem wells, major pieces of this complex puzzle have still been missing. Which additive performs best in my well? How much additive should be used? What spacer system should be incorporated? What are my chances of controlling gas migration on this particular job? Is this expensive cementing system absolutely necessary?' To date these questions have been answered by limited engineering and/or past field experiences. Gas flow potential calculations determining a well's likenhood to flow have been effectively used, yet the proper engineering formulas that outline the efficient designs proper engineering formulas that outline the efficient designs of gas control slurries have remained relatively unstructured. Very recently, however, a method of evaluation relating slurry design to gas flow potential was published by Sutton and Ravi. This theoretically sound method, however, while sill in its infancy, has remained lightly tested against actual field jobs. To confirm and further analyze this more exact method of predicting a cement's gas control capability, 26 cement Jobs performed in various wells located in Michigan, Texas, and Louisiana were selected for review. This included both shallow and deep gas zones (5,600 ft through 21,000 ft) defined by gas flow potentials ranging from minor to severe. Different cement types, considered both poor and excellent for controlling gas flow by industry standards, were utilized in the field jobs. Post Job analyses was based on the presence of annular gas flow or pressure within 24 hours Of the job. P. 463