Abstract Sand control poses huge financial loses during production operations particularly in mature fields. It hinders economic oil production rates as well as damages downhole and surface equipment due to its abrasive action. Excessive sand production rates can plug the wellhead, flow lines, and separators which can result in detrimental well control situations. This paper will provide a comparative study on various sand control mechanisms by reviewing the latest advancements in sand management techniques. This study evaluates the performance of through-tubing sand screens, internal gravel pack, cased hole expandable sand screen, modular gravel pack system, openhole standalone screen, multi-zone single trip gravel pack, slim gravel pack, and chemical sand consolidation mechanisms. Various field examples from Niger-Delta, Mahakam oil and gas block, and offshore Malaysia are examined to gain an insight about the application of aforementioned sand control methods for different type of reservoirs. This study enables the operator to tackle the sand production problem according to the well construction changes during the life cycle of a well. The internal gravel pack completion system delivers a prolonged plateau production regime in shallow depths. In high drawdown conditions, chemical sand consolidation completion incurs early water breakthrough and elevated sand production. Chemical sand consolidation technique yields better results in deeper formations and its placement can be improvised by implementing coiled tubing and diversion techniques for multi-stage treatments. Depending on the well inclination, gas-water contact, producing zone type and thickness, well age, and economy, the completion types out of modular gravel pack, openhole standalone screen, slim gravel pack, and through tubing sand screen is recommended accordingly. Acquiring offset data, well log analysis, particle size distribution and performing pressure tests will improve the data quality of the obtained reservoir properties. This will further help in the selection of the most suitable sand control method for the target reservoir.

Abstract Qualification of tubular connections is an important task in well completion design for thermal wells, which experience peak temperatures of 180°C to 350°C, as well as high pressure and high temperature (HPHT) wells, which experience peak temperatures up to 180°C and pressures greater than 70 MPa. Industry protocols (such as ISO/PAS 12835:2013 for thermal wells, and ISO 13679:2019 and API RP 5C5:2017 for HPHT wells) have been developed for the purposes of evaluating the structural integrity and sealability of premium connections. In recognition of the the time and capital expense associated with completing "product line validation" for a connection design per these standards for multiple physical configurations (i.e for combinations of various sizes, weights, and grades), industry is developing a hybrid approach that supplements results from physical qualification tests with numerical simulation, such as Finite Element Analysis (FEA). To facilitate numerical modeling, extensive research work has been performed recently (e.g. Xie, Matthew, and Hamilton (2016) and Xie and Matthew (2017)) to establish a constitutive relationship for evaluating metal-to-metal sealability. It was noted in previous studies that further experimental work is required to better understand connection sealing behavior, especially the effects of surface roughness and thread compounds. This paper presents an experimental study with a series of small-scale metal-to-metal seal tests under various levels of seal contact stress and gas pressures representative of thermal and HPHT operational conditions. These tests incorporated the effects of surface roughness and thread compound. FEA was performed to model the stress conditions in the test specimens. Based on the experimental and analytical study, an updated metal-to-metal seal evaluation criterion with calibrated parameters is proposed for tubular connections used in thermal and HPHT applications.

Abstract Cooling of thermal wellbores such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) wells, is a common prerequistite to allow deployment of logging instruments due to the temperature limitation of imaging instruments’ electronics (<150°C). This paper presents a memory caliper technology housed in a thermoshield that can perform at up to 220°C, with the acquired data used to evaluate the integrity of tubulars and completion items (metal loss, deposition, deformation, and gap/hole damage), negating the need for cooling before deployment. Two cases are presented. One is a SAGD well with liner screens across the lateral section. The memory multi-finger caliper was deployed using coiled tubing and the data were successfully obtained across the lateral section with a maximum recorded temperature of 169°C. The second example is a vertical well in a steam flood field. Because of the uncertainty over the downhole temperature at the time of the well intervention, a temperature sensor was deployed in surface read-out mode above the caliper. This ensured the 220° temperature limit of the caliper would not be breached, and a maximum temperature of 208°C was recorded. The data confirm the feasibility of acquiring high accuracy/high resolution data from thermal wellbores without having to resort to manipulative cooling techniques to attain a temperature below 150°C. Enlargement of a limited entry perforation (LEP) was observed in the horizontal well and buckling was clearly detected in the vertical well. The broad measurement range of the caliper – 1.85" – 7.2" – enabled both the tubing and liner to be logged in a single well intervention, which facilitated a swift resumption of of steam injection activities. Ultimately, the high temperature MFC's ability to minimize deliberate cooling the thermal wellsbore before deployment, has time and cost saving implications throughout the life cycle of the well. Much of the existing literature examining downhole data acquistion in thermal wells, for the diagnosis of wellbore integrity issues, has relied on technologies that are unable to withstand temperatures much greater than 150°C. The ability to execute well interventions for data acquistion at higher temperatures offers the potential for empirical studies that compare the status and integrity of the wellbore completion in thermal and cooled conditions.

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.

Abstract Creep, the time-dependent deformation of rock, will increase the pressure applied on the interface between the cement and formation. The objective of this paper is to study the influence of the formation creeping effect on the cement sheath integrity and zonal isolation. It focuses on the failure behavior of the cement sheath in the long period after drilling. The paper also investigates the changing of mechanical properties of cement to avoid loss of zonal isolation. The interface pressure between the cement and formation cannot be measured directly in the field, so it will be valuable to predict this pressure through alternative methods. A Casing-Cement -Formation System (CCFS) analytical model based on linear-elasticity and Cam-Clay plasticity model was built. The CCFS model includes four layers, casing layer-cement layer- plastic creeping layer and the formation layer. This plastic- transition layer is formed because of formation creeping. The axial stress and tangential stress distribution of the cement sheath were calculated by the CCFS model. The contact pressure between the cement sheath and formation was calculated. Mohr-Coulomb yielding criterion was applied to estimate failure behavior for the cement sheath. Two case studies were performed with the new CCFS model and previous CCFS model that do not consider the formation creeping effect. The comparison between two models showed that without considering the formation creeping effect, we might underestimate failure of the cement sheath. The simulation result by our CCFS analytical model indicated that the creeping effect would make the interface between the casing and cement vulnerable to shear failure. We changed the Young's modulus and Poisson's ratio for the failed case to investigate the influence of mechanical properties of the cement material. The result showed that a lower Young's modulus and higher Poisson's ratio were preferred for improving zonal isolation. Instead of pursuing how creeping happens, this paper accepts formation creeping as a fact in the whole life of the well. The geomechanical impacts of the plastic-creeping formation, although undetectable from the surface observations, may cause detrimental consequences to cement integrity.

Abstract Steam Assisted Gravity Drainage (SAGD) is the dominant in-situ method for oil production in Western Canada. The current study analyzed the relative performance of various well-completion practices using data from 4,000 well pairs that were drilled over a decade. The data analysis provided a unique opportunity to find best operating practices. The scope of this paper is to review the performance of major thermal projects in Canada and investigating the effect of liner design and Flow Control Devices (FCDs) on well pair performance and development. Cumulative oil production and cumulative steam oil ratio (cSOR) were used as the key metrics in comparing the well performance in a SAGD operation. However, to compare different pads and different projects, it was critical to normalize the data with geological variation, well length, well spacing, and with consideration to the well failure rate, remedial completion and re-drills. In this paper we review seven thermal projects of four key operators with almost 3,500 wells and 1,200 well pairs in operation as early as 1996. All geoscience, and production/injection data have been extracted from public databases and utilized to develop a data-driven model. The reservoir thickness variation for each well was determined using available geoscience data, and through the development of a geological model based on the available core data and well logs. The model was used to define the drainage volume for each well pair, which in turn was used to assign a geological ranking to the well. The cumulative oil production and cSOR were then normalized with the geological ranking and the size of the net drainage volume. The number of well pairs in each pad and the cumulative pad production were normalized against the number of days in production and their relative decline, which allowed for comparison between pads within the same project, as well as pads from other projects. The cumulative production of the active pads in each project was used to compare the relative performance of different projects. Also, we separated the projects and wells based on their use of FCDs in the producer and injector to compare the relative performance of each technology in the field. This paper is the initial phase of the study on the role of completion design on relative well and well pad performance. The results will help completion and production engineers to better understand the well pair and pad relative performance and how to normalize the oil production data against geological variation to compare performance.

Abstract It is important to complete thermal and high-pressure/high-temperature (HPHT) wells with tubular connections that possess adequate structural integrity and sealing capacity under the severe load conditions typically experienced by these wells throughout their life cycle. Individual premium connection designs are required to be evaluated and qualified through physical tests to broadly adopted industry protocols, such as ISO/PAS 12835: 2013 for thermal wells that experience temperatures from 180°C to 350°C, and ISO 13679:2019 and API RP 5C5:2017 for HPHT wells which experience peak temperatures up to 180°C and pressures greater than 70 MPa. Recognizing the time and capital expenses associated with completing full-scale physical testing of product lines with multiple connection designs of different tubular diameter, weight, and grade, industry is developing a hybrid approach that supplements results from physical qualification tests with numerical/analytical simulation, such as Finite Element Analysis (FEA). The key challenges associated with analytical evaluation are the lack of evaluation criteria and suitable guidelines for analysis methodologies. This paper provides a review of recent work related to the development of sealability evaluation criteria; and presents guidelines to facilitate performance evaluation of tubular connections in thermal and HPHT wells through advanced FEA. For thermal well applications, this paper presents a methodology for quantitative evaluation of sealability of casing connections, as a supplement to the determination of a biased test population using FEA following ISO/PAS 12835:2013 requirement. For HPHT wells, this paper presents considerations for analyzing various testing loads, such as Test Series A (internal and external pressure cycles), Test Series B (internal pressure with bending), Test Series C (thermal and mechanical cycles), and Limit Load Cases. Analysis examples with generic premium connections are presented to demonstrate the use of the proposed analysis methodologies.

Abstract The purpose of this study is to assess the subsea well intervention capabilities in Brazil from an operator point of view and how it compares to other regions in the world, in terms of equipment availability, technology and readiness. The object of this assessment will be restricted to the well access systems, given the numerous scenarios that can drive a subsea well intervention. The intent is to identify the main challenges an International Oil Company (IOC) and/or Local Oil Company (LOC) operating in Brazil must overcome in order to keep a robust and realistic contingency plan in case of any well integrity issue. Also, similar challenges are experienced whenever production restoration is needed and/or even opportunities for production enhancement are economically assessed to viable, or not. Last but not least, well access during the last phase of a well lifecycle (plug and abandonment) is also a key element. This will be discussed further in. Until the late 90's, the subsea oil industry in Brazil was restricted to the state-run operator and the supply chain to the business had developed itself around the mindset to maidenly supply a single state-run operator demand. After the market opening and consolidation of the IOC's and LOC's in the subsea market, a lack of local supply of several goods and services started to present itself. Since well access systems are expensive and the base case is that you won't use it unless you have a problem, there's a strong unconscious desire not to worry about it until you really need it. Sharing the same view, service companies tend to enforce the sale of these kits to the operator, rather than focus on a rental solution. Moreover, when service companies provide rental solutions, they are not kept in country and mobilization fees and lead time become a showstopper on many cases. In view of the scenario described above and ways of operation of the Brazilian market IOC's and LOC's a solution will be proposed to mitigate the risk of unavailability and reduce costs based on the sharing economy principles.

Abstract Objectives/Scope Verification and testing of a wellbore barrier, in older assets has proven to be challenging. Even more so when the well has structural issues, indemnities or weak spots in the barrier envelope, that limits the possibility to get a positive pressure verification of the barrier with an applied surface pressure. The paper will air on the operational use of this novel test method and the tools used, to allow an in well verification of any type of barrier to secure the well for a repair or a upcoming P/A operation. A pilot job case history will be included to illustrate use of the principles. Methods, Procedures, Process Find a suitable location with necessary support and strength in the well. If installing a mechanical barrier by means of a bridge plug as the primary barrier, we will monitor the installation forces in the anchoring and sealing sequence. This individual signature will be verified towards a nominal base line signature towards a library of thousands of collected installation profiles. Any abnormality can trigger a release and possible relocating of the barrier. A second verification barrier will then be installed above the primary barrier. When both installation signatures are accounted for, we can pressure test the installed barriers. This is done with a pressure inflow tool, where we introduce a calculated predetermined pressure drop between the installed primary barrier and the verification barrier. By monitoring this pressure alteration vs. the pressure above the verification barrier, we can determine if we have a verified barrier. Results, Observations, Conclusions We now have the Primary Barrier verified in the direction of flow (negative pressure test). And verification barrier as the secondary barrier (verified with a positive pressure test). If a dual barrier is requested, you can leave the verification barrier as secondary barrier. Novel/Additional Information Pressure manipulation is done with existing and proven technology and is re-usable after re-setting at surface. By monitoring this pressure alteration, we can verify the installed primary and verification barrier in one run. This without any time-consuming pressure manipulating from surface.

Abstract As conventional fishing assembly offers a degree of recovery chance, such chance can be increased by utilizing an Oscillating Fishing Tool (OFT). The OFT is a fishing Bottom Hole Assembly (BHA) component that delivers low-magnitude; high-frequency oscillation. The continuous motion that the tool provides complements the impact generated by the fishing jar. This paper reviews the successful case history in Field X, which was in fact the first utilization of OFT for a fishing application in the field. Method of analysis involve comparing fishing sequence without and with the OFT. The OFT was used in Offshore Field X to recover a mechanically stuck 550-meter long Tubing Conveyed Perforating Gun assembly inside 9 5/8" casing that could potentially lead to loss of access into the 6 oil reserves candidate perforation zones. Initially the assembly had been stuck for two days, during which conventional fishing BHA was used to retrieve it to no avail, even after jarring for most of that time. OFT was then incorporated in the final fishing BHA and operated in combination with jarring operation. After around twelve hours of oscillating and jarring, the fish was able to be released from the initial stuck point. When tripping the string out, however, the assembly was stuck at high dog-leg severity area near the surface. At that point, in combination with applying substantial overpull, OFT was utilized further to recover the entire string. Upon fish retrieval, it was evident that post detonation, the TCP gun had swelled into 8.6 inches in diameter. In summary, oscillating and jarring for thirty-six cumulative hours successfully released the swelled TCP gun assembly from the stuck occurrences. In conclusion, the operation showed that the OFT serves as a higher level of fishing tool option that offers a particular excitation mode to the stuck assembly. Stuck assembly in a cased hole presents potential loss of oil reserves. Particularly in offshore application, the situation can also be costly. With reduced chance of recovery as time passes by, operation is hindered from being able to proceed to the next completion phase. The case proved OFT to have played an important role in improving fishing probability of success and should be considered as standard fishing BHA in the future.