Day 2 Tue, June 07, 2022最新文献

{"title":"Energy Transition by Employing a Self-Healing, Reduced Carbon Dioxide Footprint Sealant in a Strategic Underground Gas Storage Project","authors":"C. Johnson, Suleyman Sari, A. Ahrenst, Irem Gozubuyuk","doi":"10.2118/209644-ms","DOIUrl":"https://doi.org/10.2118/209644-ms","url":null,"abstract":"\u0000 The Tuz Gölü underground gas storage (UGS) project is a strategic venture in Turkey's energy program. This gas storage facility will be the largest in Europe, having multibillion m3 capacity, by taking advantage of the optimal gas storage conditions offered by subterranean salt caverns. Upon reaching the reservoir, one of the important goals is to obtain hydraulic isolation between the surface and the casing. Inadequate downhole isolation may well result in interzonal communication, gas migration, casing corrosion, and sustained casing pressure. Furthermore, gas flow to surface formations and/or to the atmosphere, could impact the environment and health along with an underlying economic impact. Wellbore isolation was introduced in the form of fully salt-saturated gas control and self-healing cement systems.\u0000 When drilling into salt caverns, the foremost challenge is to minimize the dissolution of the in-situ salt formation by means of contact with water-based cementing fluids, which can lead to the creation of new flow paths. This occurrence must be prevented at all costs; otherwise, stored gas might leak through these microchannels. Unlike typical salt formations, this candidate field also contains carbon dioxide (CO2). Most wells in the field had a prognosis toward low CO2 content, so cement exposure to CO2 was not deemed an elevated risk; however, if the CO2 exposure risk increased, it would potentially generate an additional challenge both in terms of gas migration control and long-term cement integrity.\u0000 Currently, more than 100 cementing operations have been performed in the candidate field. After pumping 3,500 metric ton of cement and blending 750 metric ton of the tailored self-healing cement, more than 300 laboratory tests were performed. More than 15,000 staff-hours of testing supported construction of 32 UGS wells, fully cemented with zero health, safety, and environment (HSE) or service quality incidents and, importantly, with outstanding bond log results. Completion strings in 15 wells have already been run where wells are prepared to store gas; the ongoing project is now expanded to 50 UGS wells. Furthermore, an intrinsic benefit of the self-healing cement system is reduced CO2 footprint vs. conventional class G cement, which can be nominally 40% less CO2 per unit volume.\u0000 With involvement of local laboratories and technical experts in the region, salt-saturated gas-control and self-healing cement slurry systems have been developed and successfully deployed. Information regarding these system's liquid and set properties will be presented, along with techniques used to enhance certain cement properties. The field cases that will be presented describe how challenges were overcome in successfully sealing UGS wells in a highly saline environment, and how the self-healing technology applied in these wells is being extended to include salt-saturated systems and CO2-resistant versions elsewhere.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"74 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121039098","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Novel Methodology to Reduce Carbon Footprints: Trials of Residual Heat Recycling in China and Middle Asia","authors":"Jin Fu, Longlian Cui, Guobin Yang, Shunyuan Zhang, Chen Chen","doi":"10.2118/209691-ms","DOIUrl":"https://doi.org/10.2118/209691-ms","url":null,"abstract":"\u0000 As a mature methodology to enhance recovery of heavy oil, ultra-heavy oil and tar oil, steam assisted gravity drainage has been adopted in several oil production regions in China since 1990's. Liaohe Oilfield which is located in the northeastern part of China has become the most important production base of heavy oil in China. Heavy oil reservoirs in Kenkyak Oilfield Kazakhstan are found on a semi-dessert plain where saline soils are widely distributed. The cold production techniques used to be deployed in Kenkyak Oilfield, but the relatively low recovery rates have made the operator to carry out a feasibility research on steam injection.\u0000 The steam assisted gravity drainage technology enhances recovery rates of heavy oil, producing a large amount of heat at the same time. The thermal resources are residual heat of hot separated water from the boiler's moisture separator, residual heat of produced fluid associated by crude oil, residual heat flue gas injected into the boiler. The separated water is as hot as steam, with a flow rate of 25% of the gas injection volume. The produced fluid associated by crude oil is at 160°C, with a flow rate of 1.1 times of the gas injection volume. The flue gas is at 240-250°C, much hotter than flue gas generated by conventional boilers. The residual heat does not only affect on-site operation and management, but also results in waste of thermal energy.\u0000 Now the residual heat of produced fluid and separated water is deployed to heat supply water and fuel. Based on geological conditions and on-site operation requirements, there is neither a river to cool the residual heat, nor a common heating system to generate a large amount of thermal energy. Besides, both Chinese government and Kazakhstani government are adopting strict environment protection laws, banning direct discharge of waste water and extraction of underground water in the oilfields. A once-through boiler steam injection boiler generates humid steam with a dryness fraction of 75%, and is compatible with purified water dehydrated from crude oil. Now a research on deployment of drum-type boilers to enhance recovery rates is carrying on. A drum-type boiler has strict requirements about supply water quality. In some developed countries where the assisted gravity drainage technology is widely deployed, the mechanical vapor compression technology is much more welcome, which requires re-processing of produced waste water to obtain distilled condensate water that is compatible with a drum-type boiler. The mechanical vapor compression technology, regarded as one of the most advanced integrated technologies to reduce carbon footprints arising from SAGD, is expected to be deployed in Liaohe Oilfield and Kenkyak Oilfield in the near future.\u0000 This paper focuses on comprehensive deployment of thermal resources, based on local conditions and requirements in China and Kazakhstan, proposing several feasible solutions to reduce carbon footprints arising from heavy oil ex","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129816319","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Design and Application Evaluation of Revolutionary Inflow Control Devices Enhanced Bitumen Recovery and Thermal Efficiency in SAGD Process","authors":"Guangyue Liang, Qian Xie, Y. Liu, Shangqi Liu, Jiuning Zhou, Yu Bao","doi":"10.2118/209682-ms","DOIUrl":"https://doi.org/10.2118/209682-ms","url":null,"abstract":"\u0000 Non-uniform steam chamber caused by reservoir heterogeneity, shale interlayer, local mobile water, undulating well trajectories and improper operation, etc., severely restricts oil sands SAGD performance. Inflow control devices (ICD) achieved great success in controlling conventional water or gas coning. Inspired by this, liner and then retrofitting tubing deployed ICD have been tested since 2009 and soared in recent years. Therefore, this paper made a systematic review of ICD design, operation principle and application evaluation.\u0000 Different types of ICD applications in dozens of Canadian oil sands projects were comparatively investigated including operating principle, adaptability analysis, liner-deployed or tubing-deployed ICD, early-to-medium SAGD performance. Then a numerical simulation method incorporated the relationship of pressure drop versus mass rate at different conditions and pressure degradation due to erosion impacts is presented. The feasibility analysis of ICD deployed on injector or producer was further evaluated by numerical simulations. Besides, a set of ICD optimization design method is provided including the principles of well selection, reasonable ICD number along horizontal well section, and optimum operating conditions, etc.\u0000 Revolutionary ICD technology has become an effective way of greatly improving SAGD performance in recent years. According to the statistical data, most ICD are deployed on producers rather than injectors, which is also explained by numerical simulations of technical feasibility evaluation. In order to deal with uneven steam chamber growth, the number of tubing deployed ICD dramatically increases in recent years. The proportion of liner and tubing deployed ICD is 58% and 42%, respectively. However, there are big differences in SAGD performance of different ICD wells. Some ICD wells is worse in SAGD performance and even damaged by sand production. Based on absorbing the knowledge of field application, the behavior of different types of ICD was compared to guide the selection. Then the workflow of ICD optimization design method was provided by calculating conformance and allocated liquid volume according to the relationship of pressure drop versus mass rate. The operation principle is suggested to facilitate lower subcool but zero subcool not allowed in long term due to sand production risk. On the basis of reasonable well selection, it can easily improve conformance by above 15% and oil production by over 50%. Inspired by this, ICD also applied to several multilateral SAGD well pairs to balance steam or liquid distribution along horizontal wellbore.\u0000 This paper first systematically provides various types of ICD behavior, screening criteria, design practices, operation principle and application evaluation in SAGD process. These findings are very useful for ICD design and enhancing both oil recovery and thermal efficiency in heavy oil or bitumen production.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"12 4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115519488","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Temperature Transient Modeling and Analysis for Hydraulically Fractured Wells","authors":"M. Onur, Kiymet Gizem Gul","doi":"10.2118/209653-ms","DOIUrl":"https://doi.org/10.2118/209653-ms","url":null,"abstract":"\u0000 In this work, new analytical sandface temperature solutions are developed for linear flow towards an infinite-conductivity hydraulically fractured well producing under specified constant-rate or constant- bottomhole pressure (BHP) production. The solutions apply for slightly compressible, single-phase undersaturated oil reservoirs with irreducible water saturation or liquid-dominated geothermal reservoirs. They include the effects of conduction, convection, the Joule-Thomson expansion of fluids and adiabatic expansion of the total rock and fluid system, and fluid loss fracture damage. They neglect the variation of rock and fluid properties with pressure and temperature so that pressure diffusivity and thermal energy balance equations are decoupled to obtain the analytical linear-flow temperature solutions using Laplace (for constant-rate) and Boltzmann (for constant-BHP) transformations. To validate the analytical solutions, a numerical solution is developed to solve the mass and thermal energy balance equations simultaneously and account for the variation of rock and fluid properties with pressure and temperature. We proposed a correction to fluid viscosity variation as input for the analytic solutions. The numerical and analytical solutions have been compared and verified with a commercial thermal reservoir simulator. Results indicate that the fracture surface temperature is decreasing with a square of time for constant-rate production but is constant for constant BHP production. The temperature responses for both modes of production are controlled by the adiabatic expansion of the rock and fluid properties and the thermal diffusivity of the rock. The effect of thermal conductivity plays a significant role for both production modes as the matrix permeability decreases. The fracture damage has different signatures on temperature transients at early and late times for both modes of production. The approximate analytical solutions show the information content of temperature transient data acquired from an infinitely conductive hydraulically fractured well under matrix linear flow. They are simple and can be used to perform matrix linear flow analysis jointly with pressure and rate transient data to estimate the thermal and mechanical properties of the rock and fluids. The numerical solution can be used for a more general analysis procedure based on automated history matching for constant as well as variable rate and pressure production test sequences.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121083724","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated Geo-Dynamic Modelling and Investigation of Pressure-Dependent Permeability to Increase Working Gas Capacity of a Reservoir Repurposed for Underground Gas Storage","authors":"Lin Qu, Huijuan Yu, Chuanqin Mao, T. Salter, F. Ning, Roderick Floris Matthijs Van Der Kroef, C. Cranfield, A. Kshirsagar, Limin Li, S. Randazzo","doi":"10.2118/209672-ms","DOIUrl":"https://doi.org/10.2118/209672-ms","url":null,"abstract":"\u0000 Natural gas consumption will grow significantly in coming decades in response to cleaner energy initiatives. Underground gas storage (UGS) will be key to addressing short term supply and demand dynamics during this energy transition.\u0000 This paper presents a study on the XiangGuoSi (XGS) fractured carbonate, gas reservoir onshore China which had been converted to UGS. The focus is on how integrated studies around a shared subsurface model including coupled simulation can be used to maximise working gas storage capacity and hence increase deliverability to meet future peak gas demand. Critically, the robust integration of this study raised confidence sufficiently to propose that reservoir pressure during future gas storage cycles could be increased above the original (pre-production) pressure.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"443 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127575574","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fly Ash Nanoparticle-Stabilized Emulsions for Improve Mobility Control Application","authors":"Wuchao Wang, Xiaohu Dong, Huiqing Liu, Yan Peng, Zhangxin Chen, Yu Li, Yunfei Guo","doi":"10.2118/209646-ms","DOIUrl":"https://doi.org/10.2118/209646-ms","url":null,"abstract":"\u0000 Nanoparticles have demonstrated their capacity to increase emulsion stability by forming what is known as a Pickering emulsion, which is predicted to improve EOR processes by improving conformity control. The goal of this work is to develop a novel way of beneficially utilizing the main waste product from coal power-generation plants - fly ash - by generating fly ash nanoparticle-stabilized emulsions for improved mobility control, especially under high-salinity conditions.\u0000 First, the ball-milling method was used to decrease the grain size of fly ash, which was too big for injection into reservoirs. Second, fly ash nanoparticles were used to measure the synergy between nanoparticles and surfactants in the creation of oil-in-brine emulsions. Third, the emulsion stability was tested using a microscope and a rheometer with three different surfactants (cationic, nonionic, and anionic). Finally, oil replacement experiments were conducted using intra-formation heterogeneous cores to investigate the recovery enhancement effect of in situ injection of fly ash nanoparticles and cationic surfactant (CS).\u0000 Thermally treated fly ash (TTFA) nanoparticles with an average size of 150 nm were produced using nano-milling and thermal treatment techniques. The use of either a cationic or nonionic surfactant in conjunction with nanoparticles resulted in strong and stable emulsions. The cationic surfactant had the greatest synergy, while the anionic surfactant had the least, indicating that electrostatic interactions with the surfactant and the liquid/liquid interface were key factors. The in-situ emulsion formed by the fly ash nanoparticles and the cationic surfactant (FA-CS) produced an additional 8.5 % of the original oil in place (OOIP) recovery after waterflooding. This indicates that the emulsion has better mobility control performance and higher crude oil recovery.\u0000 This study not only has the potential to minimize the amount of surfactant used for emulsion-based EOR mobility control of fly ash nanoparticles but also to sequester fly ash in the subsurface strata.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"30 11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133761276","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Impact of CCUS for Improved Oil Recovery on CaCO3 Scaling Potential of Produced Fluids","authors":"Giulia Ness, K. Sorbie, Ali Hassan Al Mesmari, S. Masalmeh","doi":"10.2118/209676-ms","DOIUrl":"https://doi.org/10.2118/209676-ms","url":null,"abstract":"\u0000 Unlike other CCUS technologies, CO2 EOR has been widely implemented at a commercial level and on an industrial scale. In CO2 EOR, CO2 can be injected on its own or alternated with water in CO2 WAG (water-alternating-gas). Both applications have a direct impact on produced fluid compositions influencing GOR, water cut, CO2 concentration and consequently Ca2+, alkalinity and pH. The variation of fluid compositions has an inevitable impact on the scaling potential of produced fluids and on the resulting level of scale formation and its mitigation strategy.\u0000 The aim of this work is to investigate the scaling potential changes for a wide range of CO2 WAG scenarios in a high salinity carbonate reservoir in the Middle East using input data from reservoir modelling simulations and running multiple sensitivity studies. The main scale formed in this reservoir is calcium carbonate (CaCO3).\u0000 The equilibrium reservoir water, the produced water chemistry profiles from downhole to stock tank and the scaling risk profiles are modelled using a commercial integrated PVT and aqueous phase software. A rigorous scale prediction procedure previously published by the authors is applied to accurately calculate scale risk trends for variable production scenarios.\u0000 As CO2 increases in the WAG cycle, reservoir pH drops but the equilibrium with CaCO3 rock causes an increase in alkalinity. This results in more CaCO3 precipitation in the production system where pressure drops and CO2 flashes off solution. Hence, these results show unequivocal detrimental impact of CO2 WAG on the calcium carbonate scaling potential of produced fluids. This leads to a need for operational and/or chemical adjustments to the scale management program when this technology is deployed.\u0000 Whilst in this field some CaCO3 scale is predicted to form downhole, but this is not a severe problem although it may need to be addressed. The separator is operated at a sufficiently high pressure that calcium carbonate is not expected to form there. Changing operating pressures and CO2 and H2S concentrations can shift some of the problem to the separator, but if this remains at high pressure there will be no scale precipitation here. However, the calcium carbonate scale will predominantly precipitate at stock tank conditions.\u0000 Implementing green technologies such CCUS is fundamental to achieving net zero goals and this work clearly shows that actions need to be taken to manage the associated CaCO3 scale problems in the produced fluids to make this application successful.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114601135","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Driving Factors for Purity of Withdrawn Hydrogen: A Numerical Study of Underground Hydrogen Storage with Various Cushion Gases","authors":"G. Wang, G. Pickup, K. Sorbie, E. Mackay","doi":"10.2118/209625-ms","DOIUrl":"https://doi.org/10.2118/209625-ms","url":null,"abstract":"\u0000 The central objective of this study is to improve our current understanding of the hydrodynamic processes arising when hydrogen (H2) is stored in subsurface porous media. In this work, we compare the use of two cushion gases, namely carbon dioxide (CO2) and methane (CH4), for H2storage ina synthetic aquifer. The impacts of viscous instability, gravity segregation, capillary trapping, and CO2 solubility in water on the recovery performance are investigated in detail.In the context of H2 storage, wefocus on both the amount and the purity of the H2that is back produced. A series of very fine-scale numerical simulationswas performed in 2D vertical systems using a fully compositional simulator. A simple three-stage operation strategy (cushion gas injection, H2 injection and H2 production) was designed to trigger the flow behaviour of interest. Based onscaling theory, we analysed the impacts of various mechanisms on the H2 recovery performance, from viscous dominated to gravity dominated flow regimes. Viscous instability and permeability heterogeneity may strongly degrade the purity of the back produced H2. No matter whichgas (CO2 or CH4) is selected as the cushion gas, the less viscous H2 infiltrates the cushion gas, meaning that the displacement does not proceed in a piston-like fashion. In the viscous-dominated scenario, H2 may even bypass the cushion gas of CO2, which subsequently leads to early breakthrough of the cushion gas and thus a dramatic reduction in H2 purity during back production. However, this effect does not arise in the case with CH4 as cushion gas. On the other hand, in the gravity-dominated case, the less dense H2 accumulates above the cushion gas and there is no flow infiltration or bypassing occurring in cases studied here. Therefore, the overall H2recovery performance is much better in the gravity-dominated regime than that in the viscous dominated regime. Finally, we demonstrate that it is important to include the solubility of CO2 when used as cushion gas in aquifer systems. This isbecause CO2 dissolution in water may significantly reduce its gas volume and lead to early water breakthrough during back production.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122530329","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Differentiation of Cement & Creeping Formation Behind Casing Key to Successful Plug and Abandonment","authors":"Shilpi Gupta, Helge Vindheim, Amit Govil, Guillermo Obando, Apoorva Kumar, Gaurav Agrawal, Shaktim Dutta","doi":"10.2118/209655-ms","DOIUrl":"https://doi.org/10.2118/209655-ms","url":null,"abstract":"\u0000 The Gyda field in the North Sea operated by Repsol was proven in 1980 and the platform started producing in 1990. In June 2017, the Norwegian authorities approved the decommissioning plan for the Gyda field. The decommissioning scope included the permanent plugging of 32 wells in the field. Decommissioning is estimated to cost several hundred million dollars and is expected to finish in 2022. As per the NORSOK standards, each well needs to have confirmed barriers to isolate inflow zones, both for preventing from flowing to the surface and hindering crossflow between them. Cement and creeping formation are both considered to be potentially effective barrier elements. However, the criteria and verification methods used to confirm formation creep and cement as barrier elements are different and hence require an innovative interpretation technique which is presented in this paper.\u0000 As per the regulations and standards, it is critical not only to evaluate the quality of the circumferential bond for cement and formation creep but also to determine their respective bond length. The most important measurement to accurately determine those criteria in each well is through the ultrasonic and flexural attenuation tool. However, interpretation to differentiate formation creep from cement presents challenges, especially when they have similar ultrasonic properties. Quite often, they coexist at the same depths on different sides behind the casing. Barrier evaluation becomes even more challenging with added complexities such as borehole mud settling due to high deviation, high eccentricity, casing damage, or presence of a microannulus. This paper discusses the techniques and interpretation methods used to accurately evaluate barrier elements, differentiate between cement and formation creep, estimate the tops of cemented areas, and eliminate complex challenges posed by mud, deviation, eccentricity, and wet microannulus sections.\u0000 Successful and accurate determination of the potential presence and location of annulus barrier elements has been fundamentally important for Repsol to meet the regulatory requirements. A special interpretation technique was established using integrated data evaluation to differentiate creeping formation from cement. This technique successfully determined accurate barrier intervals, helping to meet all the regulatory requirements. The processes and methods have been audited and evaluated by the Petroleum Safety Authority Norway.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"44 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131581429","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Case Study: Analysis of Refracturing Crack Orientation-Angle and Extension-Length in Tight Gas Reservoir, Sulige Gasfield of China","authors":"Yang Wang, Yuedong Yao, Lian Wang, Yongquan Hu, Haoru Wu, Hao Wang","doi":"10.2118/209633-ms","DOIUrl":"https://doi.org/10.2118/209633-ms","url":null,"abstract":"\u0000 Attribute to the hydraulic fracturing technology, China has carried out commercial development of the low permeability and tight gas reservoirs in Sulige Gasfield, Ordos Basin. However, the practice indicates that the gas well with hydraulic fracturing performs rapid decline rate, which generally repeated fracturing technology is often adopted to enhance the economic benefits of gas field development. Therefore, the reservoir physical properties, pressure system, fluid properties, and formation parameters of fracturing engineering, such as rock characteristic parameters and original in-situ stress, are respectively summarized. Furthermore, compared with traditional hydraulic fracturing, the theory of refracturing and the simulation of crack extension are studied.\u0000 This study starts from the geological characteristics, gas reservoir properties and rock physical properties of the main layer. Firstly, based on the theory of rock elasticity, the problem of crack induced stress field is analyzed. Then, combined with the rock media and mechanical environment around the initial artificial crack, the mathematical model of the induced stress field of the initial artificial crack is established. Meanwhile, the semi-inverse solution is applied to solve the mathematical model. Finally, the analytical formula of crack induced stress is obtained, by introducing Fourier transform, complex variable and Bessel function integral formula.\u0000 Taking a fractured gas well in Sulige Gasfield as an example, only single-phase gas flowing is considered and depletion constant pressure production is adopted. The results show that: (a) The induced stress is mainly related to the net pressure on the crack wall, in which the induced stress in the direction of the original horizontal principal stress increases with the net pressure. (b) Through the simulation of tight gas reservoir performance, we found that the change of production induced stress is great with the longer production time, the lower bottom-hole flowing pressure and the more variable anisotropy of reservoir permeability. (c) The area of in-situ stress reorientation is also greater, and the new crack gets easy to change direction. (d) This simulation can help engineers realize that the initial artificial crack induced stress and gas well production induced stress all change the initial in-situ stress, thence, the new crack of refracturing will not fracture along the direction of the old crack.\u0000 In this case, the Orientation-Angle and Extension-Length are recalculated, after calculating the current stress state in the direction of the original principal stress, and production time, bottom hole production pressure and others that affect the new crack are analyzed. More importantly, this research could be applied for other similar refracturing wells with vertical cracks in tight gas reservoirs worldwide and provides a research basis for the afterward study of the description of volumetric crack.","PeriodicalId":332644,"journal":{"name":"Day 2 Tue, June 07, 2022","volume":"142 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133276578","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}