Day 3 Wed, February 14, 2024最新文献

{"title":"New Generation Fracturing Fluid with Superior Proppant Transport and Oil Displacement Functionalities","authors":"Genyao Lin, Jiangshui Huang, Bryant Richardi, Stephanie Yu, Jianshen Li, Fuchen Liu, Lijun Lin","doi":"10.2523/iptc-23290-ms","DOIUrl":"https://doi.org/10.2523/iptc-23290-ms","url":null,"abstract":"\u0000 Multifunctional fracturing fluid is desirable in the oil and gas industry as it can simplify hydraulic fracturing operations and reduce environmental impact. Traditional high-viscosity fluids, like borate crosslinked fluid, can effectively transport proppant to keep fractures open but can constrain fracture length and damage the proppant pack. Conversely, low-viscosity options like linear gels, can extend fracture length and facilitate secondary fractures, but have limited proppant carrying capabilities. Recent efforts have attempted to combine fracturing fluid with surfactants to achieve both hydraulic fracturing and improved oil recovery. However, these efforts require multiple additives and still lack sufficient proppant transportation. This study introduces a new generation fracturing fluid combining superior proppant transport and oil displacement functionalities, formulated with a unique polymer containing chemically bonded oil displacement surfactant.\u0000 The new fracturing fluid was evaluated using a range of tests, including static proppant suspension test, rheology test, coreflood, regained conductivity and oil displacement tests. The static proppant suspension test compared the new fracturing fluid with a linear gel. The fluid's rheological properties were measured using an advanced rheometer. The spontaneous imbibition Amott test was conducted to appraise the fluid's oil displacement properties. The coreflood and regained conductivity studies were conducted at 160°F to evaluate the fluid's formation and proppant pack damage.\u0000 The new generation fracturing fluid excelled in all tests studied. In the static proppant suspension test, it suspended the 20-40 mesh ceramic proppant much longer than the traditional guar-based fluid. The rheology test revealed that the 0.3wt% fluid's storage modulus G’ is higher than the loss modulus G\" across the whole spectrum of frequency tested, signifying high elasticity of the fluid. The spontaneous imbibition test demonstrated the new fluid increased the relative oil recovery rate by 12.1% compared to the control polymer. The coreflood results showed an 85.7% regained permeability for the 0.4wt% new fluid. The conductivity study showed a 94.7% regained conductivity. These results demonstrate that the next generation fracturing fluid can not only offer superior proppant transport capability but also it can be easily broken down by traditional breaker and then release the oil displacement surfactant to achieve oil displacement functionality. These features make the new fracturing fluid an excellent choice for hydraulic fracturing applications with less freshwater usage and reduced environmental impact.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"11 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527780","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":"Research and Application of Rock Typing Using Deep Learning in Prediction of Carbonate Reservoirs of H Oilfield, Iraq","authors":"Xiaoli Gao, Lv Lu, Wang Bo, Yongli Wang, Ailing Wang, Junhui Hu","doi":"10.2523/iptc-23426-ms","DOIUrl":"https://doi.org/10.2523/iptc-23426-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The loss of some important logging data especially lithology data in old oilfields and huge cost in manpower and material on drilling and coring have brought great difficulties to the development of oilfields. A new method using deep learning for rock typing is achieved to classify and count the limited logging data, establish appropriate pore-permeability (PP) relationship and reduce the risk of reservoir prediction, which provides a concise and effective way for carbonate rock prediction.\u0000 \u0000 \u0000 \u0000 In allusion to the existed problems, the paper collects, ranks the correlation between rock types and conventional logging data, which establishes a neural network model based on deep learning, divides the carbonate reservoirs into 4 types, and estimates the pore-permeability relationship for each type. Finally, a pore-permeability cloud simulation was performed based on the geo-statistical inversion to set up a high-precision reservoir static model with perfect well-seismic tie. The reliable permeability property can be obtained which helps to accurately depict the spatial distribution of the reservoirs.\u0000 \u0000 \u0000 \u0000 The carbonate reservoir of M formation for H oilfield in the Middle East is of complex pore structure with strong heterogeneity and poor relationship of the pore-permeability (PP). The logs DT, GR, Density, Porosity as the input features of deep learning is optimized to train neural network models, which are applied to the sample for testing and verification. The sample tests from the optimized neural network model are as accurate as 86.8%. The results show that rock typing using deep learning and well logs found a non-linear mapping relationship which effectively and reasonably divided the carbonate reservoirs into 4 types. The geological statistics and stochastic simulation in geo-statistical inversion organically combine seismic information with rich reservoir parameters such as porosity, rock typing, permeability and so forth. The permeability inversion result is highly consistent with the drilling data, which means the reservoir distribution patterns and regularity have been greatly improved, the local characteristics of the reservoir have been described more detailed and accurate.\u0000 \u0000 \u0000 \u0000 The paper establishes and optimizes a neural network model based on deep learning which extends the divided rock typing to the whole oilfield. The estimated permeability as new pore-permeability relationship was applied to the geo-statistical inversion, which achieved the high-resolution spatial prediction of reservoir parameters and satisfied the fine reservoir characterization. It reduces the huge cost on drilling and coring, also provides a concise and effective approach to improve the reservoir estimation and production efficiency.\u0000","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"10 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528211","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 Four-Dimensional Geostress Evolution Model for Shale Gas Based on Embedded Discrete Fracture Model and Finite Volume Method","authors":"Qiang Wang, Yufeng Wang, Jinzhou Zhao, Yongquan Hu, Chen Lin, Xiaowei Li","doi":"10.2523/iptc-23476-ms","DOIUrl":"https://doi.org/10.2523/iptc-23476-ms","url":null,"abstract":"\u0000 Stress changes associated with reservoir depletion are often observed in the field. The four-dimensional stress evolution within and surrounding drainage areas can greatly affect completion of infill wells and refracturing. To accurately predict the four- dimensional stress distribution of shale gas reservoir, a coupled fluid- flow/geomechanics model considering the microscopic seepage mechanism of shale gas and the distribution of complex natural fractures (NFs) is derived based on the Biot's theory, the embedded discrete fracture model (DEFM) and finite volume method (FVM). Based on this model, the four-dimensional stress prediction can be realized considering the mechanism of adsorption, desorption, diffusion and slippage of shale gas and the random distribution of NFs. The results show that in the process of four- dimensional stress evolution, there will be extremes of σxx, σyy, σxy, Δσ, α and stress reversal area at some time, and the time of occurrence of extremes is different at different positions. The key to determine this law is the pore pressure gradient with spatio-temporal evolution effect. Different microscopic seepage mechanisms have great influence on the storage and transmission of shale gas, which leads to great differences in the distribution of reservoir pressure and four-dimensional stress. The influence of microscopic seepage mechanism should be considered in the process of four- dimensional stress prediction. The larger the initial stress difference is, the more difficult the stress reversal is. When the initial stress difference exceeds a certain limit value, the stress reversal phenomenon will not occur in the reservoir. This research is of great significance for understanding the four-dimensional stress evolution law of shale gas reservoir, guiding completion of infill wells and refracturing design.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"9 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527624","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":"Smart Computational Algorithms for the Prediction of Interfacial Tension between Water and Hydrogen – Insights into Underground Hydrogen Storage","authors":"S. Kalam, Mohammad Rasheed Khan, Muhammad Arif","doi":"10.2523/iptc-23310-ms","DOIUrl":"https://doi.org/10.2523/iptc-23310-ms","url":null,"abstract":"\u0000 Hydrogen has the potential to play a critical role in the energy transition economy for the next decade, aiding in decarbonization. Hydrogen has a two-pronged utility in the energy mix by acting as a fuel and supporting the distribution of other renewable sources through electrolysis. Nevertheless, a critical hurdle in achieving autonomous hydrogen-based energy transition is the safe, reliable, and economical methods of underground storage mechanisms. Consequently, this requires comprehending interaction processes between hydrogen and subsurface fluids that can affect the storage capacity with a major role of interfacial tension (IFT). Accordingly, this work used smart computational intelligence methods to delineate IFT predictions between H2 and H2O mixture for various pressure/temperature conditions and density variance.\u0000 A systematic approach was adopted to implement predictive models for IFT prediction by utilizing an experimental data set. A comprehensive statistical analysis is performed to achieve model generalization capabilities and improve control over the most relevant input parameters. Consequently, IFT is demarcated as a function of two readily available inputs of pressure, temperature, and calculated density difference. Various smart approaches in this work are proposed by developing an IFT predictor using Support Vector Regression, XGBoost, and Decision Tree algorithms. Machine learning model training is enhanced using a k-fold cross-validation technique combined with the exhaustive grid search algorithm. Post-training, the developed models are tested for reliability using blind datasets reserved for this purpose.\u0000 A fair comparison between model efficiency is ensured by using an in-depth error analysis schema that includes various metrics like the correlation of determination, average error analysis, graphical error analysis, and scatter plots. This generates a relative ranking system that weighs various factors to classify one model as the most efficient. For the IFT prediction problem, it was found that the XGBoost was aptly able to yield high efficiency and low errors. This stems from how XGBoost functions map the non-linear relationship between pressure, temperature, density difference, and the IFT. It was also observed that enhanced intelligent model training through multiple techniques resulted in optimized hyperparameters/parameters. Lastly, a trend analysis was conducted to confirm the robustness of the developed XGBoost model.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"51 12","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527976","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":"Emulsified Epoxy Resin for Mitigating Sand Production","authors":"F. F. Chang, F. Liang, Christie Lee, Paul Berger","doi":"10.2523/iptc-23393-ms","DOIUrl":"https://doi.org/10.2523/iptc-23393-ms","url":null,"abstract":"\u0000 Sand production from unconsolidated or crushed weakly consolidated formations due to high reservoir fluid flow velocity leads to operational problems and limits their potential. Many techniques are practiced by the completion and production engineers to combat such challenge. This paper discusses the development and testing of a novel polymeric resin formulation that consolidates sand grains to form a high regained permeability and high compressive strength rock matrix, allowing high production rate without sanding concern.\u0000 The new chemical solution utilizes a low viscosity water external epoxy emulsion to strengthens the bonding of sand grains while maintains flow capacity. The chemical formulation contains two components that can be batch mixed at wellsite, injected by coiled tubing or drill pipe, and shut-in in the formation to cure for 24 to 48 hours depending on the reservoir temperature from 200°F to 320°F. Unlike most of the currently used resin consolidation products, by which post flush is required to maintain opening of the pore space, the emulsion separates during the curing process with epoxy attaching to the sand surface while the water phase occupies the pore to help keep the flow path open.\u0000 Laboratory experiments in both water or oil saturated sand packs showed the treated loose sand are well consolidated with the unconfined compressive strength significantly greater than 1000 psi and the regained permeability up to 54%. No sand production was observed in the produced fluid at high flow rates. This paper focuses on the laboratory testing of the water external emulsified epoxy. The chemical mechanism and evaluation methodology are described.\u0000 Having the water emulsified epoxy resin system allows the convention water based diverting techniques such as foam to be used during treatment of long sections. Another benefit of the water based emulsified epoxy is its operation simplicity and safety. The flash point concerns for safe field operation is completely alleviated with this chemical formulation.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"51 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527977","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":"Study on the Mechanism of Carbonate Formation Strength Degradation Induced by Water-Rock Interaction","authors":"Dujie Zhang, Daqi Li, Junbin Jin, Yulin Tu, R. Rached","doi":"10.2523/iptc-23389-ms","DOIUrl":"https://doi.org/10.2523/iptc-23389-ms","url":null,"abstract":"\u0000 The strength deterioration of the wellbore rock induced by water-rock interactions would be an important cause of the delayed instability in the Leikoupo formation located in Western Sichuan Basin, Sichuan Province, China. Taking the carbonate rock sample obtained from the Leikoupo formation as the research object, this study systematically analyzed the composition and the microstructural characteristics of the rock firstly. Then, a series of rock mechanics experiments before and after immersion in deionized water, pH=9, pH=11, and water-based drilling fluid (pH=11.5) was conducted. In order to further analyze the microscopic mechanism, the change in the ion concentrations of the immersed fluid and rock microstructures were analyzed. The results indicated that the Leikoupo formation carbonate rock was mainly limestone with developed micro-fractures. After immersion in alkaline solution, the elastic modulus and compressive strength of the rock decreased obviously. The friction coefficient of the fracture surface decreased as well. The degree of the deterioration became more significant with the increasing solution pH value and the prolonged immersion time. The analysis suggests that the dolomite in the carbonate rock undergone de-dolomitization reaction in high-temperature alkaline solution. It dissolved the micro-protrusions of dolomite on the fracture surface, so as to reduce the surface roughness. The research findings preliminarily reveal that the dissolution-crystallization-expansion mechanism of de-dolomitization reaction was the driving mechanism for the deterioration of carbonate rock due to water-rock interactions, providing a theoretical basis for the development of drilling fluid technology for stable wellbore in fractured carbonate rock formations.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"28 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528021","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":"Oxidative Hydraulic Fracturing Fluid to Enhance Production from Source Rock Reservoirs","authors":"Katherine L. Hull, Simrat Singh, Brady Crane, Rajesh K. Saini, K. Alruwaili, M. AlTammar, Y. Abousleiman","doi":"10.2523/iptc-23282-ms","DOIUrl":"https://doi.org/10.2523/iptc-23282-ms","url":null,"abstract":"\u0000 The steep production declines generally observed after hydraulic fracturing in unconventional source rock reservoirs has been attributed to several potential causes. Recently a new additive to the stimulation fluid system was proposed to extend economical longer-term production from these formations. Oxidizer-laden fracturing fluid systems are shown to create cracks and deep channels within the organic matter present in the source rock, such as kerogen, thereby increasing the source rock permeability and enhancing the hydraulic conductivity of the exposed fracture faces. To this end, the fluid design and recommendations for its application are illustrated herein.\u0000 Oxidants composed of ClOn- and BrOn- (n=0-4) are effective for kerogen depolymerization or degradation at depth. This study illustrates the beneficial effects of two specific oxidizers, sodium chlorite NaClO2 and sodium bromate NaBrO3, on kerogen-rich source rock subjected to in-situ reservoir conditions. Source rock samples were cut and polished to test the oxidizer impact on the organic and inorganic regions. Scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS) were performed on the rock surface to identify specific organic matter features. The samples were then chemically treated with varying conditions of NaClO2 or NaBrO3 (concentrations 0.013 M - 0.054 M, temperature 150 °C, and time 3-24 hours). Samples were returned to the SEM for post-treatment analysis. Furthermore, the oxidants were packaged within a slickwater hydraulic fracturing fluid system for field application, and their effects upon viscosity and friction reduction were also studied.\u0000 SEM images and EDS maps of kerogen-rich rock samples observed before and after treatment with oxidizing fluid showed a series of cracks formed throughout the organic matter domains, where increasing the concentration of oxidizer in the treatment fluid showed a clear increase in the prevalence of cracks throughout the surface. The effect of time was also observed, as short treatment times resulted in porosity/permeability creation in the kerogen, though longer treatment times were associated with more severe degradation. Optimal conditions for NaClO2 and NaBrO3 concentrations in the additive fluid systems, were different and will be herein highlighted. Each oxidizer (10-20 pptg concentration) was added to slickwater with variable friction reducer concentration (1, 2, and 4 gpt), and shear sweeps performed at both 70 °F and 180 °F. Negligible difference is observed between the viscosities of the base fluid and the fluid with either oxidant at low friction reducer concentration. Meanwhile, flow loop tests demonstrated that the oxidizer did not affect the friction reducer except to slightly boost the performance due to the salt effect on the polymer.\u0000 Two strong oxidants, available as commodity chemicals, are shown to be effective to crack kerogen and any present organic matter thus create permeable channels and ","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"27 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528024","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":"Scrubbing Spacer for Gas Storage Well","authors":"Mohd Sabri Maarof, Faizan Ahmed Siddiqi, Anouar Elhancha, Urooj Qasmi, Rodny Benjamin Masoud Zuleta","doi":"10.2523/iptc-23265-ms","DOIUrl":"https://doi.org/10.2523/iptc-23265-ms","url":null,"abstract":"\u0000 In recent years, the utilization of underground gas storage wells in the Kingdom of Saudi Arabia (KSA) has witnessed significant growth. This strategic approach enables the operator to effectively reserve natural gas for the long term and optimize the management of supply-demand dynamics.\u0000 In a natural gas storage well, the casing and the cement sheath surrounding it are critical barriers to withstand downhole stress cycles and ensure long term well integrity. Cement evaluation logs are performed, and the cement sheath quality is analyzed to decide whether the well can be completed for gas injection or remedial work is necessary. Hence, a proper cement design plays a vital role in the successful construction of such wells. A major aspect of any cement design is mud removal.\u0000 Effective removal of drilling fluids is crucial to a successful cementing operation. However, drilling fluids are becoming more resilient, especially Non-Aqueous Fluids (NAF) with increasingly complex hydrocarbon chains and strong reverse-emulsions. Therefore, it is ever more difficult for conventional spacers to clean NAF-containing wellbores and water-wet casing surfaces, resulting in poor cement bonding and lack of zonal isolation. Conventionally, a surfactant is used to invert the emulsion and water-wet the surfaces, while a mutual solvent is added to disperse and dissolve the oil droplets. Since the formulations of NAF vary greatly, a universal spacer formulation suitable for all applications does not exist.\u0000 To solve this problem, the spacer performance is augmented by introducing scrub fibers to promote mud removal. The fibers enhance flow shearing and attract non-aqueous compounds through hydrophobic-hydrophobic interaction. A rotor-cleaning test using a sandblasted rotor facilitates the evaluation the spacer cleaning performance in the laboratory and tune its formulation.\u0000 Consequently, the enhanced spacer design has improved cement bonding to casing and wellbore across the critical well interval. The clear improvement seen on the cement evaluation logs has been well recognized. So far, a 100% success rate is maintained.\u0000 An engineered scrubbing spacer which includes a fiber in the spacer to substantially improve NAF removal during cementing operations. It has also been shown to improve the removal of water-based drilling fluids that are sticky and difficult to clean.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"45 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528003","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":"Maximizing Drilling Efficiency: A Novel Solution to Handle Wellbore Ballooning in High Pressure Formation Through Applying a Fit-For-Purpose Drilling Fluid and Managed Pressure Techniques","authors":"A. H. Oqaili, T. N. Alzarea, C. Iturrios","doi":"10.2523/iptc-23279-ms","DOIUrl":"https://doi.org/10.2523/iptc-23279-ms","url":null,"abstract":"\u0000 Oil and gas drilling activities are being constantly evolving to master the domain of drilling into abnormally pressurized formations interbedded with depleted zones. Drilling companies venture into more challenging fields in order to satisfy the global demand for hydrocarbons. One of the major focus areas in drilling operations is well control incident as it can be a safety hazard and lead to lost time and cost. The focus area of this paper will be discussing how to tackle wellbore breathing as it can be tricky to manage as a well control situation.\u0000 Wellbore breathing (or wellbore Ballooning) phenomenon imposes several well-control challenges with the rig conventional blowout preventers and drilling fluid monitoring equipment. There are many state of the art innovative methodologies in detecting wellbore breathing. The nature of wellbore breathing requires intelligent diagnostic tactics to eliminate the chances of a kick scenario, which could be leading to prolonged flow checks and constant increases of the drilling fluid density to stabilize the well. Once this happens, expectedly the scenario may further lead to a series of loss and kick scenarios that can result in operational challenges such as stuck pipe or wellbore sidetracking. Moreover, leading to series of curing operations under these challenging circumstances. Deploying losses curing techniques has to be tailored since traditional cement curing tactics may remain unsuccessful with ballooning effect resulting in cement contamination jeopardizing the objective. Essentially controlling bottom-hole pressure while attempting to cure losses is detrimental to the success of the process. Wellbore breathing requires intensive care in wells with narrow mud weight profiles. Furthermore, routine operations, such as tripping or cementing the well, requires additional measures to maintain the well integrity and quality at best.\u0000 Instead of attempting to control the well by constantly adjusting the mud weight and performing extensive flow checks, this paper will highlight how this situation can be dealt with in a safe and systemic approach. The paper will highlight three different (but combinable) approaches, including the utilization of wellbore strengthen fluid particles to help preventing the wellbore breathing issue from happening in the first place, the utilization of a rotating control device (RCD) to help mitigating wellbore breathing consequences and stabilizing the well, including the technique of placing a cement plug to strengthen the problematic formation utilizing managed pressure cementing (MPC) techniques, and lastly, the paper will show how managed pressure drilling (MPD) equipment can help to detect and resolve the wellbore breathing issue.\u0000 The implementation of the mentioned techniques above can result in a safer drilling operation to the rig crew, avoidance of nonproductive time (NPT) and overall, better well integrity.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"155 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528480","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":"An Effective Metal Organic Framework (MOF) for Selective Barium Removal from Oil Field Waters","authors":"J. Hou, F. Alghunaimi, T. Huang, N. Aljuryyed","doi":"10.2523/iptc-24302-ms","DOIUrl":"https://doi.org/10.2523/iptc-24302-ms","url":null,"abstract":"\u0000 Highly efficient capture of barium from oil field produced water is a meaningful task in water treatment, such as for water disposal, irrigation or barium recycling. Here, we propose a barium trap with metal-organic framework (MOF) modified by strong barium combining group (sulfate and sulfonic acid group). This MOF material can remove > 90% barium selectively in high salinity produced water, regardless of the ion interferences.\u0000 The Zr-BDC-NH2-SO4 material was prepared by 2-aminoterephthalic acid and Zr(SO4)2·4H2O assembly at 98 ºC under stirring for 16h. After washing with water and ethanol, the material was dried at 60 ºC overnight, and then characterized by XRD and SEM. In the adsorption experiment at room temperature, 0.2 g Zr-BDC-NH2-SO4 MOF material was immersed in series of concentrations of barium in deionized water or high salinity water (TDS > 60,000 ppm) for 2 hour’s incubation. The barium concentration was from 20 to 5,000 ppm. Barium concentration after Zr-BDC-NH2-SO4 removed was measured by ICP-MS.\u0000 In the theoretical structure of the MOF material, the sulfate anions located around the Zr6-cluster in Zr-BDC-NH2-SO4, and the sulfate anions are coordinated to the Zr6 inorganic node by a monodentate O atom. The sulfate anions in Zr-BDC-NH2-SO4 is fully exposed, indicating that Zr-BDC-NH2-SO4 will be easier to bind with Ba2+ ions. The adsorption results in deionized water shown that the adsorption amount of barium increase with initial barium concentration. At 5,000 ppm, the amount can be as large as 200 mg/g. And the adsorption curve was linear and did not reach the highest value yet. More importantly, the adsorption amount in produced water is almost the same comparing to deionized water, indicating that the adsorption of barium is not affected by salts in produced water because of the high selectivity of the sulfate functioned material.\u0000 This work provides a remarkable, sulfate group functionalized MOF with very high barium uptake capacity which surpasses most of reported adsorbents. It can selectively capture barium from high salinity oil field waters.","PeriodicalId":518539,"journal":{"name":"Day 3 Wed, February 14, 2024","volume":"33 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528174","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}