Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
casing pressure
Sustained Casing Pressure: One of the Most Important Factors Determining the Integrity of Deepwater Wells
Wang, Yanbin (China University of Petroleum, Beijing) | Xin, Shilin (China University of Petroleum, Beijing) | Gao, Deli (China University of Petroleum, Beijing) | Wang, Jinduo (China University of Petroleum, Beijing) | Ning, Bo (Guangzhou Marine Geological Survey) | Zhao, Zihao (China University of Petroleum, Beijing)
Abstract While drilling and completion of deepwater wells, the cement top is usually several hundred meters below the mudline, which results in a portion of completion fluid entrapped in the technical casing annuli between wellhead and the top of cement. The temperature of the wellbore would be redistributed due to the thermal fluid during well testing or production. Thus, high thermal stress and additional pressure would be induced in the annuli of technical casing, which is proved to be one of the major threats to well integrity. In this paper, a new model predicting the sustained casing pressure (SCP) is established, which is consisted of two sub-models: heat transfer model and sustained casing pressure model. The former model is thoughly considered to provide boundary and initial conditions for the latter model. The influence of wellbore heat transmission in the casing strings and properties of completion fluid in the annulus on the temperature distribution is considered in the heat transfer model. The mechanical model is presented with consideration of the coupling thermal effect of the casing and the fluid. On this basis, a numerical simulation is given to verify the validity of the theoretical model. Good consistency has been shown between the theoretical result and the numerical simulation. If the temperature increment is high enough, the SCP is enough destructive to destroy the casing and subsea wellbore. Analysis results also show that the physical parameters of the fluid in the annuli, the cement top and the annuli volume have significant influence on the SCP. Both the increase rate and the maximum limit of the SCP increase with the cement top. Appropriate increase of the annuli volume is an acceptable way to delay the pressure increase. The temperature and pressure coupling effect need to take special consideration in casing design of deepwater wells. The model in this paper provides more accurate boundary and conditions for SCP analysis. The calculation results have important theoretical and engineering significance, especially for the casing program design and the subsea wellbore integrity evaluation of deepwater wells.
- North America (0.68)
- Asia > China (0.47)
New Experimental Results Show the Application of Fiber Optic to Detect and to Track Gas Position in Marine Risers and Shed Lights on the Gas Migration Phenomenon Inside a Closed Well
Santos, Otto (Louisiana State University) | Almeida, Mauricio (Louisiana State University) | Sharma, Jyotsna (Louisiana State University) | Kunju, Mahendra (Louisiana State University) | Chen, Yuanhang (Louisiana State University) | Waltrich, Paulo (Louisiana State University)
Abstract The main objective of this manuscript is to present and to discuss the results and significant observations gathered during 13 experimental runs conducted in a full-scale test well at Louisiana State University (LSU). The other two objectives of this manuscript are to show the use of distributed fiber optic sensing and downhole pressure sensors data to detect and to track the gas position inside the test well during the experiments; and to discuss experimental and simulated data of the gas migration phenomenon in a closed well. An existing test well at LSU research facilities was recompleted and instrumented with fiber optic sensors to continuously collect downhole data and with four pressure and temperature downhole gauges at four discrete depths within an annulus formed 9 5/8″ casing and 2-7/8″ to a depth of 5025′. A chemical line was attached to the tubing allowing the nitrogen injection at the bottom of the hole. The research facilities were also equipped with a surface data acquisition system. The experiments consisted in injecting nitrogen into the test well filled with water by two means: either injecting it down through the chemical line or down through the tubing to be subsequently bullheaded to the annulus. Afterwards, either the nitrogen was circulated out of the well with a backpressure being applied at surface to mimic an MPD operation or left to migrate to the surface with the test well closed. During the runs, the three acquisition systems (fiber optic, downhole gauges, and surface data acquisition) recorded all relevant well control parameter for a variety of gas injected volumes (2.0-15.1 bbl), circulation rates (100-300 GPM) and applied backpressures (100-300 psi). The experimental results gathered by the acquisition systems were very consistent in measuring gas velocities inside the well. The numerical model predictions matched very close the pressure behavior observed in the experimental trials. In the gas migration experiments, it was observed that the bottomhole pressure is not carried to the surface and that this pressure is a function of the volume of gas injected in the well. These facts are supported by the numerical simulation results. The manuscript shows the possibility of the use of fiber optic and downhole pressure sensors information to detect and to track the gas position inside a well or the marine riser during normal or MPD operations. Additionally, the vast amount of experimental data gathered during the experiments in which the nitrogen was left in the closed well to migrate to surface helped shed lights on the controversial issue concerning the surface pressure build-up while the gas migrates to surface in a closed well. Numerical simulations were all instrumental for supporting the findings.
- North America > United States > Louisiana (0.34)
- North America > United States > Texas (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Abstract The point of well integrity is how to produce hydrocarbon from the source (well) to surface safely. The main goal of this paper is to keep well in operation due to gas supply and demand in the field, identify tubing/ annulus communication, mitigate any excessive annulus pressure, and corrective action of tubing casing leaks refer to industrial code and Well Integrity Management System (WIMS). One of the wells in "P" platform, namely "W" well has found a leak between production tubing and production casing ("A" annulus) and no any excessive presure from "B" & "C" annulus in this case. There is no way to shut-in the well due to gas supply and demand in our field and the well must be operate safely by conduct annulus pressure monitoring, pressure limit calculation, regular bleed-off program, and modify surface facilities. Pressure limit is calculated by determine MAASP and MOASP to ensure working pressure and bleed-off program are managed. Annulus pressure bleed-down program is one of mitigation action to manage excessive pressure in annulus. We have provided technical recommendation, specify mitigate engineering solution to reduce risks, and modify surface facilities to keep wells in operation. Based on jobs result, we have done to operate all wells safely with efficient technology, deliver fluid from 3 ½" production tubing to surface facilities, perform cost optimization, and minimize production loss. We have also performed to manage and maintain annulus casing pressure successfully related to well integrity implementation. Furthermore, In this case, there is no serious hazard during these conditions in offshore field. The paper will share success story, method, and detail procedure to keep well operation by maintain annulus casing pressure in offshore field. We have done this method by efficient technology/ solution with lower operating & construction cost and there is no production loss during operation. We confidence this method can be applied successfully not only for our field, but also other business/ operating units which has similar conditions.
- Asia (0.95)
- North America > United States > Texas (0.28)
Integrity Evaluation and Management in High Temperature High Pressure and High Production Rate Wells in Southwest China
Zhu, Dajiang (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Fan, Yu (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Zhang, Huali (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Li, Yufei (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Zhang, Lin (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Wang, Chuanlei (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Wang, Xiaolei (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Chen, Hao (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Lu, Linfeng (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute) | Duan, Yunqi (PetroChina Southwest Oil & Gasfield Company Engineering Technology Research Institute)
Abstract The Longwangmiao (referred to as LM) gas field in southwest China has characteristics of high temperature (144~156 °C), high pressure(75~76 MPa), and high production rate (70~100×10 m/d). Serious well integrity problems were encountered in the development process; 21% of 56 wells were subjected to sustained casing pressure (SCP)(≥20 MPa). Downhole leak detection logs indicated the main cause was tubing connection leakage at a depth range of 0~2400 m. Wellhead growth was present in 33 wells and 4 wells exhibited gas leakage through wellhead valves. Theoretical analysis and field tests were conducted to investigate and manage well integrity problems. A method to calculate the allowable pressure for different annuli was proposed based on string strength analysis, and downhole leak detection was conducted using ultrasonic leak detection method. A multi-string mechanical model to predict wellhead growth was established and the threshold values were calculated under different gas rates. According to the structure of wellhead, a method based on ultrasonic phased array to detect the work state of the wellhead was adopted, which measured the actual thickness of key valves to evaluate service life. For wells with SCP, the allowable pressure for different annuli was calculated and the pressure management charts were drawn and all wells were in steady production. Downhole leak detection showed that SCP in the A annulus (annulus between the tubing and production casing) was caused by connection leakage of tubing. In newly completed wells, a premium connection was adopted based on tests under cyclic structural and environmental thermal loads that the connections may encounter at various production phases, and the total ratio of SCP in newly completed wells decreased by 31.4%. Wellhead growth was predicted and compared with actual data, which showed an increase in average accuracy of 20~30% compared to the results from the WellCAT software. Sensitivity analysis revealed that the length of un-cemented casing and the production rate were the critical factors affecting the wellhead growth. The valve leakage of FF level material wellhead was caused due to corrosion after the removal of the coating, and no leakage was detected in the HH level material wellhead. Thickness survey showed that the average reduction was 0.085 mm~0.23 mm for HH wellhead, and 1.12 mm~2.24 mm for FF wellhead.
- Asia > China > Sichuan > Sichuan Basin > Moxi Field (0.99)
- North America > United States > Louisiana > China Field (0.97)
Advanced Remedial Hydraulic Isolation by Perforate and Wash Technique
Yugay, Andrey (ADNOC Onshore) | Daghmouni, Hamdi Bouali (ADNOC Onshore) | Nestyagin, Andrey (ADNOC Onshore) | Abdulsallam, Fouad (ADNOC Onshore) | Morales, Annie (ADNOC Onshore) | Salem, Gamal Yousef (ADNOC Onshore) | Al Ameri, Saleh (ADNOC Onshore) | Suleiman, Ali Yahya (ADNOC Onshore) | Kumar, Sandip (ADNOC Onshore) | McPherson, Daniel (Archer Oiltools) | Kjonnerod, Andre (Archer Oiltools) | Bakri, Mousa (Al Mazroui Group) | ElMobaddr, Ali (Al Mazroui Group)
Abstract Well Cementing can be divided into two phases – primary and remedial cementing. Primary cementing may have 3 functions: casing support, zonal isolation and casing protection against corrosion. First two functions are commonly recognized while the third one might be a point of discussion, as the full casing coverage with 100% clean cement is not something common in most of the fields. In fact, poorly cemented areas of the casing may become negatively charged and create a zones of accelerated corrosion rate. This paper is about main role of cementing - zonal isolation. The process of primary cementing assumes that cement slurry is being pumped into the casing and displaced outside. After wait on cement time (WOC) it becomes hard, develops compressive strength and creates impermeable seal that ensures hydraulic isolation. Old and well-known technique, it still remains one of the most challenging rig operations. It is unlikely to find a service company that would guarantee 100% cement displacement behind the casing all the way from top to bottom. Main challenges in this region are quiet common for many other fields – displacement in deviated sections, losses before and during cementing, exposure to pressure during cement settling. In case the main target is not achieved (no hydraulic isolation behind the casing) – we may observe behind casing communications resulting in sustainable pressures in casing-casing annuluses. In this situation the remedial cementing takes place. It's function is to restore isolation so the cement can work as a barrier that seals off the pressure source. Despite of the good number of sealants available on the market (time, pressure, temperature activated) that can be injected from surface to cure this casing-casing pressure, Company prefers not to do so unless there is a proven injectivity capability that would allow for the sealant to reach deep enough, to protect aquifers in case of outer casing corrosion. Otherwise that would be just a ‘masking" the pressure at surface. Therefore in general Company prefers rig intervention to cure the pressure across the cap rock in between the aquifers and the reservoir. Those aquifers are illustrated on the Figure 1 below: More details on Company casing design, cement evaluation issues, sustained casing pressure phenomena and challenges have been mentioned previously [Yugay, 2019].
Novel Application of Epoxy Resin to Eliminate Sustained Casing Pressure Without Costly Downhole Well Intervention - Case History from East Kalimantan, Indonesia
Guna, Yogi Adi (Halliburton) | Frank, Michael (Pertamina Hulu Sanga Sanga) | Rochman, Novianto (Halliburton) | Putra, Thomas Herdian Abi (Halliburton) | Irvan, Mohammad (Pertamina Hulu Sanga Sanga) | Fitriansyah, Alfatah (Pertamina Hulu Sanga Sanga) | Kurniawan, Ibnu (Pertamina Hulu Sanga Sanga)
Abstract An operator recorded 1100 psi of sustained casing pressure between a 9-5/8" casing and a 3.5" production tubing annulus seven days after the cementing operation was completed for the 3.5" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well. To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength. The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed. The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.
- Asia > Indonesia > Kalimantan (0.41)
- Asia > Indonesia > East Kalimantan (0.41)
- Asia > Middle East > UAE (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.91)
Successful Implementation of the PMCD Technology for Drilling and Completing the Well in Incompatible Conditions at Severo – Danilovskoe Oil & Gas Field
Krivolapov, Dmitry (Schlumberger) | Masalida, Ivan (Schlumberger) | Polyarush, Artem (Schlumberger) | Visloguzov, Vyacheslav (JSC VCNG) | Averkin, Alexey (JSC VCNG) | Rudykh, Artem (JSC VCNG) | Ivanov, Pavel (JSC VCNG)
Abstract This paper discusses the successful implementation of PMCD (Pressurized Mud Cap Drilling) technology at Severo – Danilovskoe oil and gas field (SDO) located in the Irkutsk region. The abnormally high-pressure reservoir B1 and the abnormally low-pressure reservoir B5 are the target layers in this field. Wells drilling at SDO is accompanied with simultaneous mud losses and inflows conditions, especially if the strata B1 is being penetrated. Pumping lost circulation materials (LCM) and cement plugs do not solve lost circulation complications which subsequently lead to oil and gas inflows. As a result, most of such wells are getting abandoned. It was assumed that complications in this formation occurs due to the narrow safe pressures’ operating window (ECD window), therefore, the managed pressure drilling technology (MPD) was initially used as a solution to this problem. However, after the penetration of the abnormally high formation pressure B1 horizon with a pore pressure gradient of 1.86 g/cm it was found that there is no operating window. In this regard, there were simultaneous mud losses and oil and gas inflows during the circulation. The well was gradually replaced by oil and gas, regardless of the applied surface back pressure value in the MPD system. The mixing of the mud and reservoir fluid was accompanied by catastrophic contamination. As a result, the drilling mud became non - flowing plugging both the mud cleaning system and the gas separator. On the other hand, the plugging of the B1 formation with LCM did not bring any positive results. Bullheading the well followed by drilling with applied surface back pressure and partial mud losses gave only a temporary result and required a large amount of resources. An implementation of PMCD technology instead of MPD has been proposed as an alternative solution to the problem. This technology made it possible to drill the well to the designed depth (2904 - 3010 m interval). For tripping operations, as well as the subsequent running of the production liner it was necessary to develop an integrated plan for well killing and completion in extreme instability conditions. As a result of various killing techniques application, it became possible to achieve the stability of the well for 1 hour. Oil and gas inflows inevitably occurred when the 1 hour lasted. Based on these conditions, the tripping and well completion process was adapted, which in the end made it possible to successfully complete the well, run the liner and activate the hanger in the abnormally high-pressure reservoir.
- Europe (0.93)
- Asia > Middle East (0.68)
- Asia > Russia > Siberian Federal District > Irkutsk Oblast > Irkutsk (0.24)
- North America > United States > Texas > Dawson County (0.24)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Asia > Indonesia > Sumatra > Soka Field (0.99)
- (2 more...)
Abstract E&P activities are the early stage of energy production and pivotal for generating and sustaining economic growth. However, negligence and evaluating the circumstances incorrectly during these operations can lead to calamities like blowouts. This paper discusses two such tragedies, the Pasarlapudi (Krishna-Godavari) Gas Well Blowout of 1995 & Baghjan (Assam-Arakan) Oil Field Blowout of 2020, and provides possible well control measures and lessons learned. Pasarlapudi blowout incident occurred during the drilling operations. The pipe stuck-up situation at 2727m MD (Measured Depth) was detected by conducting a stretch test. Further analysis could include circulating brine, checking lost circulation and identifying casing leaks by measuring Sustained Casing Pressure (SCP), Operator-imposed Pressure (OIP), and Thermal-induced Pressure (TIP). Baghjan's gas well at the depth 3870m was producing at 2.8-3.5 MMSCFD. The aim was to plug the lower producing zone and recomplete the well in the upper Lakadong+Therria sand zone. Well was killed using brine, cement plug was placed and BOP installed. BOP was removed after the plug was set to begin the process of moving the workover rig. Well blew gas profusely during this process. Simulating a blowout and facing one, are two completely different situations. In Pasarlapudi's case, the well blew with an enormous gas pressure of 281.2 ± 0.5 kg/cm. While drilling the production hole (8.5 inch), either differential pressure sticking, presence of water-swelling clay formation or the partial collapse of wellbore formation caused the pipe stuck-up situation. By conducting stretch test along with circulating brine, root cause of this problem could be identified. If differential sticking occurred, lost circulation could be checked & cured, while keeping the hole full. Circulating brine should solve the problem of swelling clay formation while formation collapse could have occurred due to the presence of plastic formation like salt domes. In the case of Baghjan gas well blowout during workover operations, probable safety measures could include placement of 2 or 3 backup cement plugs along with kill fluid or going for squeeze cementing before placing the cement plug & kill fluid while abandoning the lower producing zone. Attempts were made to bring the well under control by adequate water spraying, installing BOP. Water was pumped through the casing valve and a water reservoir was dug near the well plinth for the placement of pumps of 2500 gallon capacity. Proper safety measures should be used even when they're not the cheapest to avoid repetition of treatments and detrimental situations. SCP, OIP and TIP should be measured periodically whenever possible and the root cause of situations like lost circulation, pipe stuck-ups, kicks, casing leaks should be identified before proceeding towards drastic remedial operations. Innovations in countering well-control situations should be promoted invariably.
- Phanerozoic > Cenozoic > Paleogene > Eocene (0.69)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.47)
- Geology > Rock Type > Sedimentary Rock (0.69)
- Geology > Mineral (0.68)
- Geology > Structural Geology > Tectonics (0.48)
- Asia > India > Tripura > Assam-Arakan Basin (0.99)
- Asia > India > Assam > Tinsukia District > Assam-Arakan Basin > Schuppen Thrust Belt > Baghjan Field (0.99)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin (0.99)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Casing and Cementing (1.00)
- Health, Safety, Environment & Sustainability > Safety (1.00)
Study of Ultrasonic Logs and Seepage Potential on Sandwich Sections Retrieved from a North Sea Production Well
Skadsem, Hans Joakim (University of Stavanger (Corresponding author) | Gardner, Dave (email: hans.j.skadsem@uis.no)) | Jiménez, Katherine Beltrán (NORCE Norwegian Research Centre) | Govil, Amit (NORCE Norwegian Research Centre) | Palacio, Guillermo Obando (Schlumberger) | Delabroy, Laurent (Schlumberger)
Summary Important functions of well cement are to provide zonal isolation behind casing strings and to mechanically support and protect the casing. Experience suggests that many wells develop integrity problems related to fluid migration or loss of zonal isolation, which often manifest themselves in sustained casing pressure (SCP) or surface casing vent flows. Because the characteristic sizes of realistic migration paths are typically only on the order of tens of micrometers, detecting, diagnosing, and eventually treating migration paths remain challenging problems for the industry. As part of the recent abandonment operation of an offshore production well, sandwich joints comprising production casing, annulus cement, and intermediate casing were cut and retrieved to surface. Two of these joints were subjected to an extensive test campaign, including surface relogging, chemical analyses, and seepage testing, to better understand the ultrasonic-log response and its potential connection to rates of fluid migration. One of the joints contained an apparently well-defined top of cement (TOC) with settled barite on top. Although the settled material initially provided a complete seal against gas flow, the sealing capability was irreversibly lost as part of subsequent testing. The two joints have effective microannuli sizes in the range of tens of micrometers, in agreement with previous reports on SCP buildup in wells. On a local scale, however, we observed significant variations in cement quality from both the log results and the seepage testing. Further, we found qualitatively very good correlations between seepage-test results and the log results for the bond between cement and casings. The best bonded cement was found directly above a production casing collar, where a short segment of well-bonded cement prevented measurable steady-state seepage of nitrogen. Additional tests involving internal pressurization of the production casing suggested that certain annular-seepage characteristics are well-described by an effective microannulus at the cement/casing interfaces. We consider the two sandwich joints to be highly representative and relevant for similar mature wells that are to be abandoned.
- Europe > Norway > North Sea (0.82)
- North America > United States > Texas (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Mineral > Sulfate (0.34)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/11 > Valhall Field > Tor Formation (0.99)
- (12 more...)
ABSTRACT: Wells play an important role in subsurface activities such as oil/gas exploitation, carbon dioxide (CO2) and hydrogen storage. During these activities, wells are submitted to various mechanical and thermal loadings which can lead to the creation of fractures in the near-well region (cement sheath and rock formation), and thus be potential leakage paths. Analytical and numerical understanding of the stress distribution that may lead to fractures around the near-well is therefore crucial. Depending on the casing, cement sheath, formation properties, and the in-situ stresses, the analytical model predicts the induced stresses which can lead to fracture creation, while the numerical tool is used to model the propagation of these fractures. A modified discrete element method (MDEM) is used in the numerical simulations. The results show that the fracture creation and propagation not only depend on the casing pressure, initial in-situ stresses, and pore pressure, but also on the formation rock's mechanical properties such as the Young's modulus. 1. Introduction Wells are needed in various subsurface activities including oil/gas exploitation, greenhouse gas storage, etc. The construction of these wells can be simplified as follows: a hole goes through different formations, a steel hollow cylinder (called casing) is run into the hole, and a cement paste in injected into the annular space, which hardens to become the cement sheath (Figure 1). One of the main concerns in well construction is to achieve zonal isolation, which prevents downhole fluids that are under high pressure to leak and flow up to shallow formations or to the surface in an uncontrolled manner. However, during their life, wells are submitted to various mechanical and thermal loadings which can create radial fracture in the cement sheath and surrounding, and thus compromise their integrity. It is therefore important to investigate the mechanism controlling the fractures creation and propagation as well as their extension from the cement sheath to rock formations nearby. It was shown that the main failure mechanics following loadings applied to the casing include inner and outer debonding at the casing/cement and cement/rock interfaces, respectively, shear damage, radial cracks and axial disking (Bois et al., 2012; Bois et al., 2011). Most of these failure mechanisms have been confirmed in laboratory experiments where crack creation and propagation are observed after mechanical loading on the casing (Anya et al., 2020; Goodwin and Crook, 1992; Skorpa et al., 2019; Skorpa et al., 2018; Vrålstad et al., 2019). The observed cracks are not only limited within the cement sheath but can propagate also into the rock formation nearby.
- Europe (0.68)
- North America > United States > Texas (0.28)