Cement Annulus Research Articles

Analysis of Interfacial Debonding of Geopolymer Annular Sealing in CO2 Geo-sequestration Wellbore

For the geological sequestration of atmospheric CO2 to be viable, it is important that leakage of stored gas back to the atmosphere is prevented for a long period. Apart from other modes of failure, damage of the bond between interfaces can open up migratory pathways for leakages of CO2 to occur. A stress induced debonding mechanism for well bore interfaces has been studied. A numerical modelling approach was used to investigate a wellbore composite cylinder system using finite element software. Analysis was performed for the wellbore annular cement sheath, both for static pressure and temperature increase/decrease. In addition, geopolymer, a novel acid resistant cementitious binder, has been considered as an annular cement system. From analysis, it has been observed that debonding can occur at discrete locations for the wellbore pressure and/temperature increase. However, for the wellbore pressure and/temperature decrease, it was found that stress-slip failure occurs when tensile normal stresses along interfaces equal the interfacial bond strength. In addition to that, for pressure and/temperature decrease, shear stresses developed in the circumferential direction appeared insignificant in debonding failure. Thermal dilation of wellbore material can help preventing discrete debonding of wellbore interfaces in the case of wellbore pressure and temperature increase. Conversely, a wellbore temperature decrease contributes to microannular formation along interface because of the material shrinkage effect.

Advanced Cement Integrity Evaluation of an Old Well in the Rousse Field

The Rousse field, located in the Lacq basin in the southwest of France, is a site for a pilot carbon dioxide (CO2) storage project operated by Total. Since 2010, CO2 has been injected into a depleted gas field at a depth of 4.5km through RSE-1, a 45-year old production well converted to an injection well.Older wells are commonly recognized as the most likely pathway for CO2 to migrate from the injection zone to other zones or to the surface. A number of factors could increase the potential risk for these wells: completions and production history may have created defects in the sealing elements (cement, steel and elastomers); the history itself may not be known in sufficient detail to estimate a reliable risk figure and finally the injected or produced fluids may have corroded the structure.Old wells, whether they are converted to injectors or are in the path of the injection pressure field, could require renewed evaluation and preventive repairs as part of the field-level containment management plan, if their integrity assessment request so.As part of the due diligence process, advanced cement and steel evaluation logging tools were run in the RSE-1 well to investigate the bottom kilometer of the two kilometer-thick caprock. The 3D integrity map produced by the acoustic logging tools was analyzed for the presence of connected defects (pathways) that could lead to unwanted CO2 migration. The logs were also compared to the original 40 year old low-resolution sonic log to assess the extent of degradation, if any.A particular issue for wells drilled before the 1990's, when technological advances almost eliminated the problem, is that of mud channels left behind during the cement placement process. These defects present the highest risk because of their relatively large flow area. Since the well was completed in 1967, special attention was paid to the occurrence, connectivity and extent of channels. Even though imaging of the cemented annulus revealed an eccentered casing, almost lying on the rock face, and an oval borehole, the few mud pockets trapped between casing and rock were confirmed to be intermittent, with good cement providing hydraulic isolation between them. The comparison of the through-casing caliper to the formation sonic log enabled identification of borehole breakouts, caused by stress

Numerical simulation of Sector Bond log and improved cement bond image

The two principal functions of a primary cement job are to provide support for the casing and to provide hydraulic isolation between zones. A poor cement job may cause many issues during the well production. Therefore, cement bond evaluation is very important in well completion. The Sector Bond log (SBL) has been widely used for cement bond evaluation for years. The SBL tool has eight pairs of directional transmitter-receivers, which are equally distributed in azimuth and used for identifying channels and channel azimuths. To better understand SBL, using a parallel 3D finite difference algorithm, we numerically simulated acoustic responses of the SBL under a variety of cement bond scenarios and investigated the sensitivity of the integral amplitudes to channel size and its azimuth. We further developed a new approach to image potential channels in cement annulus using the integral amplitudes. The comparisons between conventional SBL images and the reprocessed ones using the new approach showed significant improvement on both synthetic and field data.

Design and Manufacture of Swell Packers: Influence of Material Behavior

In all well completions (oil and gas fields), effective cement job is necessary for zonal isolation. Failure of cement annulus because of large stresses has been reported in various studies, requiring huge costs in remedial intervention. Swellable packers have emerged as a new manufacturing equipment/technique able to replace conventional cement completion. These packers are custom-manufactured by vulcanizing specially developed swelling elastomer elements onto petroleum pipes. Especially designed and manufactured to suit a particular set of downhole conditions, swell packers are being used in a variety of petroleum applications such as zonal isolation and water shutoff in fractured reservoirs, slimming down of oil wells through replacement of conventional cementing, sand screening, reservoir compartmentalization, etc. Performance analysis and seal design improvement is not possible without reliable information about material response of swelling elastomers. This article summarizes the results of a series of tests performed to determine the swelling behavior of a water-swelling and an oil-swelling elastomer, with and without acid induction. Experimental setup was designed in consultation with petroleum and rubber engineers. Volume, thickness, and hardness of elastomer samples were measured before swelling and periodically after swelling over a one-month period. Test conditions were chosen to replicate actual oilfield conditions.

A theoretical study on formation shear radial profiling in well-bonded cased boreholes using sonic dispersion data based on a parameterized perturbation model

Interpretation of sonic data can be challenging in the presence of a steel casing that has a strong influence on elastic waves propagating along a borehole. The cement annulus behind the casing together with drilling-induced near-wellbore alteration causes radial heterogeneity in the propagating medium. It is necessary to study the influence of such heterogeneities on borehole waves and estimate the radial extent of near-wellbore alteration in terms of radial variation of velocities away from the casing. To this end, we based our study on the model of a fluid-filled well-bonded cased borehole surrounded by a cylindrically layered formation. The formation is isotropic and purely elastic, and can be either fast or slow. Borehole monopole and dipole dispersions for this kind of model can be obtained from a root finding mode-search routine. A modified perturbation model based on Hamilton’s principle is used to predict changes in borehole dispersions caused by formation heterogeneities. A two-layer formation model as the reference state is introduced, which always provides normal dispersive reference dispersion for calculations of perturbation integrals for fast and slow formations. Radial variations of the formation shear velocity can be expressed in terms of a parametric exponential profile. Consequently, estimation of these parameters in the assumed profile yields the radial variation of the formation shear slowness away from the casing. Numerical results using synthetic examples are presented to demonstrate the validity of this radial profiling methodology.

Calculation analysis of sustained casing pressure in gas wells

Sustained casing pressure (SCP) in gas wells brings a serious threat to worker safety and environmental protection. According to geological conditions, wellbore structure and cement data of gas wells in the Sichuan-Chongqing region, China, the position, time, environmental condition and the value of SCP have been analyzed. On this basis, the shape of the pressure bleed-down plot and pressure buildup plot were diagnosed and the mechanism of SCP has been clarified. Based on generalized annular Darcy percolation theory and gas-liquid two-phase fluid dynamics theory, a coupled mathematical model of gas migration in a cemented annulus with a mud column above the cement has been developed. The volume of gas migrated in the annulus and the value of SCP changing with time in a gas well in Sichuan have been calculated by this model. Calculation results coincided well with the actual field data, which provide some reference for the following security evaluation and solution measures of SCP.

Annular Pressure Reduction During Primary Cementing

Annular pressure reduction during cementing is a major factor causing annular gas flow. It has been widely accepted and proven experimentally that the pressure reduction phenomenon results from the shear stress opposing downward motion of slurry undergoing volume reduction. The models that have been proposed to describe this process are based on the gel strength and shear stress developments in time and ignore system compressibility. They explain the pressure reduction process observed in the lab where compressibility of the system is very small. However, the models cannot explain the pressure reduction patterns observed on the field where compressibility is significant and the time-dependent effects of cement slurry volume loss significantly contributes to the process. The paper presents a mathematical model combining the effects of gel strength, volume reduction, and compressibility of cement slurry to describe pressure loss in the annular cement column. Results from the model, shown in the paper, compare very well with the data from the laboratory and field tests. Also, the simulated results explain discrepancies between the pressure loss patterns observed in the lab and field tests.

Technology Focus: Well Construction (May 2011)

Technology Focus This year, most of the well-construction papers focused on long-term durability in high-pressure/high-temperature (HP/HT), tight gas/-shale, steamflood, and carbon-capture and -storage (CCS) environments, a shift toward nonconventional wells. Previously, we discussed the growing awareness of the value of measuring cement mechanical properties and modeling mechanical stresses imposed upon the cemented annulus in HP/HT, deepwater, and steamflood applications. Recognition of the technology’s value has now expanded into CCS and tight gas applications. Paper SPE 139668 discusses the many aspects and value of modeling cement-placement mechanics, cement mechanical properties, and imposed stresses. It also provides excellent tutorial insight into the complexity of modeling cement behavior in fluid and solid states. As discussed last year, lost circulation and narrow pore-/fracture-pressure windows remain key challenges in achieving casing points and targeted cement coverage. Paper SPE 130319 details field results for drilling a liner to setting depth and cementing it with a new automated managed-pressure-drilling system while providing a nearly constant bottomhole pressure, a very promising technology. Traditionally, casing- and tubing-design engineers have used a deterministic stress-limits approach that uses the API Bulletin 5C3 and the von Mises criterion. However, depending upon which of the different empirical equations and safety factors are used, the resulting tubular design may be significantly over- or underdesigned. Paper SPE 134550 details a new design methodology that uses a 3D finite-element model, variation in tubular dimensions, sensitivity modeling, and stochastic study to develop a better design specification. Manny Gonzalez, SPE, Alliance Manager for Chevron ETC, noted that when applying new metallurgies, such as titanium and high-end corrosion-resistant alloys, this statistical approach becomes critical because there is no single guide for use of the current API formulas. Well Construction additional reading available at OnePetro: www.onepetro.org SPE 142150 • “Ongoing Development of Cementing Practices and Technologies for Kuwait Oil Company’s Deep HP/HT Exploration and Gas Wells—Case History” by M.J. Al-Saeedi, SPE, Kuwait Oil Company, et al. SPE 132541 • “Determining Production-Casing and -Tubing Size by Satisfying Completion, Stimulation, and Production Requirements for Tight-Gas-Sand Reservoirs” by Y. Wei, SPE, C&C Reservoirs, et al. SPE 131489 • “Solid-Expandable Tubular Combined With Swellable Elastomers Facilitates Multizonal Isolation and Fracturing, With Nothing Left in the Wellbore To Drill, for Efficient Development of Tight Gas Reservoirs in Cost-Effective Way” by M. Ghufran Anjum, University of Engineering & Technology, Lahore, Pakistan, et al.

Stability of a leakage pathway in a cemented annulus

The risk minimization of carbon dioxide (CO2) storage relies to some extent on well integrity assurance. While chemical reactions between the constitutive materials of the wellbore - such as cement - and stored CO 2 do not jeopardize the efficiency of a defect-free cement sheath, the reactive flow through an existing pathway in a cemented annulus may alter its initial properties, and thus change the associated risk. On one hand, the cement will react with the CO2 rich fluid, and be leached away by the leaking flow. On another hand, under specific conditions, the released minerals can re-precipitate downstream and clog the pathway. The evolution of a CO 2 leak through a pre-existing leak path in the cement sheath is examined theoretically and numerically. A numerical model of the flow has been built, that takes into account the particular physics and geometry of the problem. The governing equations are investigated in order to identify the driving mechanisms and define the dimensionless groups that rule the process, leading to a reduction in the dimension of the parameters space. We use this analysis to predict the domain of stability of the defect by extracting a general criterion corresponding to the clogging conditions. © 2010 Elsevier Ltd. © 2011 Published by Elsevier Ltd.

Interface debonding as a controlling mechanism for loss of well integrity: Importance for CO2 injector wells

The concept of CO2 storage relies on the long-term sealing properties of both the geological trap and the wells needed to inject and monitor CO2. Well integrity, a classical topic in the oil and gas industry, is thus critical for the performance of any CO2 storage complex in terms of containment. Thanks to the very low permeability of cement (typically less than 0.1 mDarcy); a properly cemented well ensures hydraulic isolation between reservoirs layers and shallow aquifers. Moreover, such low matrix permeability limits the cement/ CO2 interactions over the active period of a storage complex (of the order of 100 years) to a few meters. Leaks from a cased and cemented well, if any, are known to occur only through defects: mud-channel (in case of poor cement placement), cracks within cement and more importantly micro-annulus at the casing/cement or/and cement/formation interfaces. This last category of defects can lead to substantial leakage rate. Its importance has been recognized by the oil and gas industry since the 1960's leading to the study of cement bonding properties. In the scope of CO2 storage, the understanding, modeling and monitoring of the occurrence of micro-annulus becomes of prime importance. We analyze the complete loading history of a cemented completion from cement placement to routine well operations. Further to classical failure type assessment used in the oil and gas industry (i.e. fail/no fail, good cement/bad cement), we aim at quantifying the vertical extent, azimuthal coverage and width of the created defects to adequately transform failure types into leakage pathways. Such a prediction of connected defects/leakage pathways along a cemented well imposes to consistently integrate the effects of lithology, geomechanics, cement placement (fluid loss, hydration), completion design and knowledge of pressure and thermal variation during the life of the well. The modeling of such a problem can be made tractable by recognizing the intrinsic hierarchy of lengthscales of a cemented well (i.e. the cement annulus is much thinner than the well dimension). The original three-dimensional problem is reduced to a much simpler two-dimensional one, which in turn can even be further reduced to a one-dimensional configuration in a lot of practical cases. Typical cases of interface debonding due to well de-pressurization and thermal cooling taking place after cement placement are carefully analyzed. Furthermore, we specially focus on injectors. Despite the use of all current best practices during well construction, the injection in itself can lead to the propagation of a debonding crack between cement and casing or cement and formation due to the high pressure generated at the perforations level. Such a problem has already been reported in hydraulic fracturing operations, and is a reasonable explanation of observed well leaks for injectors. A consistent model predicting the initiation and propagation of interface debonding during injection operations is then compared to carefully designed laboratory experiments. Such experiments also confirm that the azimuthal coverage of the interface debonding is only partial (i.e. less than 360°), an observation consistent with cement evaluation logs acquired on CO2 injectors. Finally, best practices to achieve and retain well integrity of CO2 injectors are highlighted from a careful examination of the results of both the model and the experiment. © 2011 Published by Elsevier Ltd.

Experimental assessment of brine and/or CO 2 leakage through well cements at reservoir conditions

Two sets of experiments on typical Class G well cement were carried out in the laboratory to understand better the potential processes involved in well leakage in the presence of CO 2. In the first set, good-quality cement samples of permeability in the order of 0.1 μD (10 −19 m 2) were subjected to 90 days of flow through with CO 2-saturated brine at conditions of pressure, temperature and water salinity characteristic of a typical geological sequestration zone. Cement permeability dropped rapidly at the beginning of the experiment and remained almost constant thereafter, most likely mainly as a result of CO 2 exsolution from the saturated brine due to the pressure drop along the flow path which led to multi-phase flow, relative-permeability effects and the observed reduction in permeability. These processes are identical to those which would occur in the field as well if the cement sheath in the wellbore annulus is of good quality. The second set of experiments, carried out also at in situ conditions and using ethane rather than CO 2 to eliminate any possible geochemical effects, assessed the effect of annular spaces between wellbore casing and cement, and of radial cracks in cement on the effective permeability of the casing-cement assemblage. The results show that, if both the cement and the bond are of good quality, the effective permeability of the assemblage is extremely low (in the order of 1 nD, or 10 −21 m 2). The presence of an annular gap and/or cracks in the order of 0.01–0.3 mm in aperture leads to a significant increase in effective permeability, which reaches values in the range of 0.1–1 mD (10 −15 m 2). The results of both sets of experiments suggest that good cement and good bonding with casing and the surrounding rock will likely constitute a good and reliable barrier to the upward flow of CO 2 and/or CO 2-saturated brine. The presence of mechanical defects such as gaps in bonding between the casing or the formation, or cracks in the cement annulus itself, leads to flow paths with significant effective permeability. This indicates that the external and internal interfaces of cements in wells would most probably constitute the main flow pathways for fluids leakage in wellbores, including both gaseous/supercritical phase CO 2 and CO 2-saturated brine.

Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 106817, "Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores," by Theresa L. Watson, SPE, T.L. Watson & Assocs. Inc., and Stefan Bachu, Alberta Energy and Utilities Board, prepared for the 2007 SPE E&P Environmental and Safety Conference, Galveston, Texas, 5–7 March. Implementation of carbon dioxide (CO2) storage in geological media requires proper assessment of the risk of CO2 leakage from storage sites. Leakage pathways may exist through and along wellbores that penetrate or are near the storage site. One method of assessing the potential for CO2 leak-age is by mining databases that usually reside with regulatory agencies. Introduction CO2-injection schemes have been in operation since as early as the 1970s for tertiary oil recovery as miscible floods, with the indirect benefit of CO2 removal from the atmosphere. Other gas-injection schemes also are used in the oil and gas industry, such as natural-gas storage and acid-gas disposal. In the case of CO2 sequestration, the storage unit must be almost leak free to the atmosphere or other geological formations to meet safety requirements and greenhouse-gas-reduction objectives. The full-length paper focuses on human-created leak-age paths—in particular, abandoned wellbores that were drilled for oil and gas exploration and production. The analysis is based on data collected by the Alberta Energy and Utilities Board (EUB) for more than 315,000 wells drilled until the end of 2004 in the province of Alberta, Canada. EUB also records well leakage at the surface as surface-casing vent flow (SCVF) through wellbore annuli and gas migration (GM) outside casing. Background Abandonment Methods. Wells Drilled and Abandoned. For a typical openhole abandonment scenario in Alberta, regulations require that any porous zone be isolated or covered to prevent cross-flow between geological formations. In addition, useable groundwater must be covered with cement and isolated from potential hydrocarbon-bearing zones. After the downhole cement plugs have been set, the well must remain open for inspection for a minimum of 5 days. After this time, the well is checked for static fluid level or other indications of plug leakage before the casing can be cut and capped below grade level. Wells Drilled, Cased, Completed, and Abandoned. There are three main types of zonal isolation and abandonment for a typical cased-hole well after reservoir depletion.Bridge plug capped with cement above perforations.Retainer and cement squeezed into perforations.Cement plug set across perforations. Regulations since 2003 require zonal isolation behind casing and that useable groundwater be protected. In many cases, older wells were constructed with low annular cement tops, allowing many zones to be in communication behind casing. Under the current regulations, a cement squeeze would be required to achieve isolation before final abandonment. Wellbores must be abandoned with inhibited fluid inside the casing and be pressure tested to a minimum of 7000 kPa. Before cutting and capping the production and surface casing, the well must be checked for SCVF and

Experimental investigation of second interface cement bond evaluation

Cement bond model wells (1:10 scaled-down) were made with a gradually degrading cement annulus for cement bond evaluation of the first interface (between the casing and the cement annulus) and the second interface (between the cement annulus and the formation). Experimental simulation on cement bond logging was carried out with these model wells. The correlation of acoustic waveforms, casing wave energy and free casing area before and after cement bonding of the second interface was established. The experimental results showed that the arrival of the casing waves had no relationship with the cement bonding of the second interface, but the amplitude of the casing head wave decreased obviously after the second interface was bonded. So, cement bonding of the second interface had little effect on the evaluation of the cement bond quality of the first interface by using casing head wave arrivals. Strong cement annulus waves with early arrivals were observed before the second interface was bonded, while obvious “formation waves” instead of cement annulus waves were observed after the second interface was bonded.

Use of Finite Element Analysis to Engineer the Cement Sheath for Production Operations

Abstract Many successfully cemented wells begin to show annulus pressure buildup, which is often caused by damage to cement sheath integrity due to post-cementing operations. This problem may be temporarily dealt with by releasing the annulus pressure. However, this method of annular gas production is not a long-term solution to the problem. A finite element analysis (FEA) method has been developed to analyze the effects of various well events and operations such as cement hydration, casing pressure testing, completions and production on the integrity of the cement sheath during the life of the well. The three-dimensional FEA modeling considers the sheath's mechanical properties, such as Young's modulus, Poisson's ratio and tensile strength, in addition to confined compressive strength, and helps provide the user with a cement design that can maintain an annular seal over the life of the well. This paper discusses how a cementing design specialist can model the events upon and after cement placement to help provide a long-term seal of the annulus. The required input data is discussed and the output information is shown for example wells. Life of the Well The main purpose of the annular cement is to provide effective zonal isolation for the life of the well so that oil and gas can be produced safely and economically(1). To achieve this objective, the drilling fluid should be removed from both the wide and narrow annulus and the entire annulus should be filled with competent cement. The cement should meet both the short-term and long-term requirements imposed by the operational regime of the well. Traditionally, the industry has concentrated on the short-term properties that are applicable when the cement is still in slurry form. This effort is necessary and important for effective cement slurry mixing and placement. However, the long-term integrity of cement depends on the material/mechanical properties of the cement sheath, such as the Young's modulus, the tensile strength and the resistance to downhole chemical attack. Considering properties of the cement sheath for long-term integrity is critical if the well is subjected to common changes in the pressure and temperature of the cased well. After cement is placed in the annulus, if no fluid immediately migrates to the surface, short-term properties such as density, rate of static gel strength development and fluid loss of the cement may have been designed satisfactorily. However, recent experience has shown that after well operations such as cement hydration, casing pressure testing, completions and production, the cement sheath could lose its zonal isolation capabilities to provide zonal isolation(1). This failure can create a path for formation fluids to enter the annulus, which pressurizes the well's annulus, and could render the well unsafe to operate. The failure can also result in premature water production that can limit the economic life of the well. Failure of the cement sheath is most often caused by pressure or temperature-induced stresses inherent in well operations. Loss of isolation can shorten or destroy the life of the well because of corrosive fluid attack on the casing and cement sheath and/or sustained gas pressure on the casing annulus.

Structural Integrity of Casing and Cement Annulus in a Thermal Well Under Steam Stimulation

Abstract Steam stimulation is one of the viable methods to extract heavy oil from oil sand reservoirs. In this thermal process, the injection well is subjected to high temperatures. Numerical simulations were used to investigate the structural integrity of the well in such a high temperature environment. In this study, stresses in the metal casing, cement annulus and surrounding shale formation were examined in detail to evaluate if the induced stresses exceed the material strengths under varying boundary conditions. These include the effect of heating rate, poor cement and shale formation properties. Introduction In Alberta, thousands of deviated wells are drilled through shale formation to extract heavy oil from underneath oil sand formation using thermal recovery processes. Thermal deviated wells in shale impose more technical challenges than conventional wells in consolidated rock because of their unique features. Thermal recovery processes, such as steam assisted gravity drainage and cyclic steam stimulation, involve high temperature operations up to 300 °C. Shales found in Alberta are compaction type without strong cementation, and have been known to swell and lose structural integrity upon exposure to water-based fluids. The occurrence of casing equipment impairment and failure after years of service in a shale formation are frequent. A completed deviated well is made up of a series of annular rings of steel casing, oil well cement and shale of varying thicknesses. There are differences in mechanical, hydraulic and thermal properties among these materials. The overall response of a thermal well subject to heating is governed by not only each material, but also the properties of interfacial steel-cement and cement-shale interaction. Material properties of steel, oil well cement and shale have been well studied separately. However, the behaviour of steel-cement and cement-shale interfaces have not received much attention because the interaction behaviour is very complex, dependent on the imposed boundary conditions. In a well completion, a borehole is drilled and advanced with drilling mud. Then, steel casings are inserted into the drilled hole filled with mud. The mud in the annular space between the steel casing and the drilled hole wall is removed by a clear wash or spacer fluid, followed by the cement slurry. In an idealized situation, all drilling mud should be removed and the annular space should be filled with cement slurry. However, the complete displacement of drilling mud by the spacer fluid and cement slurry may not be achieved. Often a residual mud layer adheres to the inside and outside surfaces of the borehole and casing, respectively. The thickness of this layer depends on the displacement processes (fluid velocity and annular space) and fluid rheology and density. Undesired mixing can be induced because there are differences in fluid rheology and density of drilling mud, washer fluid and cement slurry (non-Newtonian fluids). Local channel or fingering could occur in narrow spaces since the fluid displacement takes place in a narrow eccentric annular configuration bounded by the ircumferential surfaces of the drilled well and the steel casing(1).

Microannulus Leaks Repaired With Pressure-Activated Sealant

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 91399, "Microannulus Leaks Repaired With Pressure-Activated Sealant," by David W. Rusch, SPE, Seal-Tite Intl.; Fred Sabins, SPE, Cementing Solutions Inc.; and John Aslakson, SPE, W&T Offshore Inc., prepared for the 2004 SPE Eastern Regional Meeting, Charleston, West Virginia, 15-17 September. Sustained casing pressure (SCP) is a serious problem that is prevalent in most of the oil-producing regions of the world. Annular pressure can be a significant safety hazard and has resulted in blowouts on a number of occasions. SCP is the result of fluid migration in the annulus. The most common path for fluid migration is through channels in the annular cement. An injectable pressure-activated sealant was used to seal channels in the annular cement of several wells in the Gulf of Mexico (GOM). Introduction Fluid migration through the annuli of well-bores can result in a condition known as SCP. SCP is pressure that rebuilds in the annulus after being bled down. The integrity of all wellbores deteriorates with age. Cracks and fissures caused by factors related to cement composition, thermal stress, hydraulic stress, and compaction develop in the annular cement. The most significant cause of SCP in outer casing strings is a poor cement bond that results in cracks and annular channels. The cracks and microannulus channels provide a path for high-pressure fluids to migrate. A significant flow of high-pressure fluids can result in an underground blowout or failure of wellbore integrity.

Bond of cement grouted reinforcing bars under constant radial pressure

A ribbed rebar or rock bolt, grouted with Portland cement is the most common type of reinforcement in geomechanical projects such as tunnels, rock slopes and foundations. Due to the frictional nature of the bond slip the normal stress acting on the rebar is the most important parameter controlling the bond capacity of the reinforcement. The more the confining stress, the higher would be the mobilized load bearing capacity of the system. To quantify this effect, series of laboratory tests were designed to study the effect of confining pressure on the bond capacity. A modified triaxial Hoek cell (usually used for testing the strength of rock samples under radial confining pressure) was used to facilitate application of a “constant radial confining pressure” to the grouted sample while pulling the bolt axially through the cement annulus. During test, axial load and displacement of the bolt as well as the radial dilation of the grout was recorded and stored in computer using a data acquisition system. The results show a non-linear relation between the increase of bond capacity and confining pressure. The radial dilation is quantified also as a function of confining pressure. A peak-residual behaviour is also a characteristic of these results which shows the importance of limiting the deformation of rock blocks to avoid entering into the post peak range of the reinforcement with low values of bond.

Assessment of Salt Loading on Well Casings

Summary Assuring the integrity of subsalt wells in the deepwater of the Gulf of Mexico throughout the field's life is a major drilling engineering challenge. The consequences of well failures may result in billions of dollars in remedial costs and lost production. On the other hand, the costs associated with overly conservative well design are significant, which motivates systematic analysis of casing loading for scenarios of interest. Simplified hole-closure and casing-design guidelines for salt, many developed for the western U.S. Overthrust Belt, are not appropriate for the relatively pure, slow-moving halite found along the Gulf Coast. Instead, our work applies knowledge gained by Sandia Natl. Laboratories from technical research and development (R&D) investigations of the Waste Isolation Pilot Plant (WIPP) and the Strategic Petroleum Reserve (SPR) to determine the magnitude and timing of salt loading on well casings in the Gulf of Mexico. If hole quality can be assured, the analyses presented show that it is not always necessary to cement the casing/borehole annulus through the salt because the subsequent uniform loading is insufficient to substantially deform the casing. This poses no threat to drilling operations or impingement on the inner casing string in the long term and results in considerable cost savings. However, if hole quality is poor, a cemented annulus is necessary, as the cement effectively transforms the potentially nonuniform loading situation into one of uniform loading. Significant benefits can accrue from quantifying the magnitude and timing of salt loading. Difficult cementing jobs and liner tiebacks can be omitted and a more aggressive well design adopted. The simplified well design, and the elimination of potentially troublesome operations, leads to millions of dollars in cost savings in individual wells.

Geomechanical Response of the Shale in the Colorado Group Near a Cased Wellbore Due to Heating

Abstract Steam-stimulation is a viable in situ thermal recovery technique for heavy oil and oil sand reservoirs. This thermal recovery process introduces many complex geomechanical problems in oil sand and overburden formations. This paper addresses the geomechanical response of Colorado shale near a cased wellbore due to heating. The temperature, pore pressure, and stress response in Colorado shale near a cased wellbore due to heating are analyzed using a coupled thermal-mechanical-hydraulic solution. The possibility of failure or fracturing of the shale due to heating is assessed. Introduction Steam-stimulation processes are currently the most viable techniques for oil recovery from oil sand reservoirs. These thermal recovery processes cause many complex geomechanical effects in the oil sand layer and the geologic overburden strata due to elevated temperatures and pressures involved in the steam injection. The study in this paper focuses on the effect of heating on shale near a cased well. Analytical solutions developed by Booker and Savvidou(1) are used to analyze the distributions of induced pore pressure, temperature, and stress near a heated wellbore. These results will be used to investigate the potential occurrence of any tensile fracture in the heated shale. Conclusions will be drawn, along with the limitations of the analysis, and recommendations made for further studies. Problem Description Figure 1 defines the problem. Steam is injected into a cased well such that the inside temperature is elevated to a constant level. Heat is continually conducted from the well to its metal casing, cement annulus, and the shale in the formation. Heating of shale causes thermal expansion of the shale structural matrix and pore fluid. Expansion of the structural matrix induces total stress changes. Expansion of the pore fluid increases the pore pressure, thereby generating pore pressure gradients and the potential for pore fluid flow. Hence, the heating process results in a thermalhydraulic-mechanical coupled process. Calculation of the changes in temperature, pore pressure, and stress changes near the heated well will require solution to this complex coupled problem. FIGURE 1: Problem description. (Available in full paper) Analytical Technique Equilibrium Equation and Constitutive Law For a saturated thermo-elastic geological medium, the equilibrium equations are: Equation (1.a) (Available In Full Paper) Equation (1.b) (Available In Full Paper) Equation (1.c) (Available In Full Paper) where σxx, σyy,..... σyz are the increase of total stress components (compressive stresses and strains are considered to be positive). In the present study, the stiffness of the solids and pore fluid are assumed to be infinite in comparison to the shale skeleton stiffness. Thus, volume changes are due to changes in temperature and effective stresses. For an isotropic thermo-linear elastic material, the stress-strain relations are given by: Equation (2.a) (Available In Full Paper) Equation (2.b) (Available In Full Paper) Equation (2.c) (Available In Full Paper) Equation (2.d) (Available In Full Paper) Equation (2.e) (Available In Full Paper) Equation (2.f) (Available In Full Paper) where the primed symbols represent effective stresses, E and ν are the drained Young's modulus and Poisson's ratio, G is the shear modulus, Ψ is the increase in temperature, and a' is the drained coefficient of volumetric thermal expansion of the geologic me

Shrinkage of Oil Well Cement Slurries

Abstract Gas leakage into and through the cemented annulus in oil and gas wells is a safety problem. The conditions for gas migration develop when the hydrostatic pressure of the hydrating cement slurry column slowly declines and finally falls below the pore pressure of a gas bearing formation. This pressure decline is mainly caused by chemical shrinkage of the cement. A low shrinkage will reduce the pressure decline and hence the risk of gas migration. A new and simple method for measurement of total chemical shrinkage at high temperatures has been developed. It has proved to be reliable and sensitive for monitoring the cement hydration process. The equipment was used to show that there is a marked difference in shrinkage behaviour for the tested slurries up to 180 ° C, probably due to a temperature effect on the cement hydration chemistry. The results confirmed the correlation between total shrinkage and cement content, and thus it follows that using more extender will reduce the likelihood of gas migration. Introduction Cement slurries are used in oil and gas wells for cementing the steel casing to the wellbore and thus sealing the rock formations from the well. Gas leakage into and through the cemented annulus is still a problem, in particular where shallow gas sands are penetrated and in deep gas wells, i.e., under high temperature and high pressure (HTHP) conditions. The leakage may manifest itself either as vertical communication between permeable gas reservoirs or migration all the way to the surface. Gas pressure in excess of the cement hydrostatic slurry pressure is the driving force behind gas migration. Reasons and mechanisms of gas migration are discussed by Levine et al.,(1) Sabins et al.(2), and Cheung and Beirute(3). Annular gas flow may be initiated when the hydrostatic pressure of the cement slurry declines and falls below the pore pressure of a gas bearing formation due to the combined effect of shrinkage, fluid loss to the porous well bore and gel strength build up. Normally a slurry volume reduction would be compensated for by contraction and downward movement of fluids from above, thus maintaining its hydrostatic head. However, during the setting process the cement slurry develops a gel structure causing it to stick to the wall thus hindering compensation of the shrinkage. The second requirement for gas migration is that the cement must enable gas flow into the cement either by permeability, channels, microannuli or microfractures before the slurry has reached a sufficient strength. Thus, the gas migration phenomenon is thought to be initiated during the transition state, from being fluid to becoming hard, i.e., between initial and final set of the cement. A low shrinkage is preferable because the resulting hydrostatic pressure decline will be lower than for a slurry with high shrinkage, i.e., pressure equilibrium between gas and slurry column is reached at a later point of time. The chemical shrinkage may be divided into two parts: external shrinkage and total shrinkage.