Day 3 Fri, March 03, 2023最新文献

{"title":"Numerical Simulation for Compaction and Subsidence During Production Period for a Large Carbonate Gas Field","authors":"S. Kusolsong, K. Adisornsupawat, P. Vardcharragosad","doi":"10.2523/iptc-23015-ea","DOIUrl":"https://doi.org/10.2523/iptc-23015-ea","url":null,"abstract":"\u0000 Many gas fields were discovered in carbonate build-ups located in Sarawak, Malaysia. One of the most challenges and well-known issue to operate these fields is the reservoir compaction and surface subsidence. In the new discovered field, which was recently discovered in 2019, the data related to stress magnitude and mechanical rock properties is very limited. The available cores were used to perform the essential rock mechanics laboratory test. The coupling between reservoir dynamic simulation and mechanical earth model (MEM) was selected as an approach to predict the episodic compaction and subsidence through the field life. The 1D mechanical modeling was then performed, calibrated with rock mechanics laboratory test, and used as the key input in 3D mechanical earth modeling. The coupling steps between dynamic and 3D-MEM were selected throughout the production lifetime when the pressure depletion is significant compared to the previous coupling step. Based on the literature review, the reservoir compaction and subsidence occur in this region was caused not only from the reversible elastic deformation but also from the effect of pore collapse in some classes of the limestone. This pore collapse during pore pressure depletion and increase in effective stress tends to have more impact to the subsidence than the normal elastic deformation. This behavior was also captured and incorporated using critical state criterion. The results of the coupling will strongly have the impact on how the platform will be designed to account for potential subsidence throughout 20 years of production. Due to the limitation of input parameters in the 3D-MEM, the sensitivity analysis was performed to assess the impact of each mechanical properties on the magnitude of the reservoir compaction and subsidence. The use of ready coupled 3D-MEM can also be further extended to other applications such as wellbore integrity, wellbore stability analysis, and mud weight optimization at any given period of time. Moreover, the impact of the compaction and subsidence in this study could leads to better planning in data acquisition such as rock mechanics data, laboratory test, and logging acquisition program to narrow down the uncertainty of the subsidence analysis and other geomechanical applications.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125347224","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":"Successful Delineation of Sand Bodies to Improve Carbon Capture and Storage Reservoir Modelling, A Case Study from the North Malay Basin, Gulf of Thailand","authors":"O. Limpornpipat, R. Uttareun, A. Satitpittakul, Takonporn Kunpitaktakun, P. Henglai, Khuananong Wongpaet","doi":"10.2523/iptc-22983-ea","DOIUrl":"https://doi.org/10.2523/iptc-22983-ea","url":null,"abstract":"\u0000 The objective of this study is to characterize sand reservoirs by using seismic inversion technique, the results were used to support CO2 storage potential identification and reservoir modeling works (storage volume calculation). The key storage targets are the saline aquifers and depleted reservoirs. These main targets were interpreted as a deposition of distributary channels occurring in the Paleo Chao Praya delta plain during Miocene. The results of this project contribute to a more accurate volume calculation for CO2 storage capacity. A rock physics feasibility analysis was carried out to understand a link between the observed seismic responses and the rock properties. Based on conclusions made in the rock physics analysis, P-Impedance could be used to delineate sand reservoir from shale, thus, a post-stack deterministic seismic inversion was selected for this reservoir characterization. Bayesian litho-classification method justifies lithology types by Probability Density Function (PDF) of P-Impedance, the resulting PDF was then applied to the inverted relative P-Impedance to create sand probability and lithology (most probable) volumes. Then, posterior validation of the lithology classification results was performed by investigating the match between the actual upscaled lithology log and pseudo lithology log from the Bayesian classification. Furthermore, the sand probability maps of the target reservoirs show an acceptable sand distribution response to the distributary channels in lower coastal plain environment that is consistent with the well results. The results of this work demonstrate how quantitative interpretation (QI) can successfully improve confidence in sand reservoirs mapping, in an area of complex faulted reservoir interval. The results presented here are beneficial for storage potential identification and reservoir modeling part, which can provide a more precise estimation of CO2 storage volume. The final results of the QI study provide good quality seismic inversion products and lithology cube, which enabled sand delineation at the target CO2 storage level. The key contributors have been ensuring optimal seismic input data, being in this case achieved through using a PSDM seismic processing technology, careful parameterization of seismic inversion process, and utilization of Bayesian classification method for lithology classification.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125428016","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":"Rock Physics Applications on Seismic-Based Reservoir Characterisation of the Gas Fields, Offshore Malaysia-Thailand Joint Development Area","authors":"P. Boonyasatphan, T. Akarapatima, Yanika Poonyachotwanich, Piyanuch Majikol, Sami Mohamed Taha Mohi Eldin, Husna Diyana Hafit, Mohd Al-Amin Abd Mutalib","doi":"10.2523/iptc-23024-ea","DOIUrl":"https://doi.org/10.2523/iptc-23024-ea","url":null,"abstract":"\u0000 The A-J gas field requires the next phase of the drilling campaign, and identifying the new targets is required. So far, target identification is based on anomaly detection of seismic attributes together with geological concepts. The new thorough rock physics analysis is conducted to get a better understanding of rock within the area and, therefore, a better attribute selection for target identification. The rock physics analysis provides an insight of rock properties within the area and reveals the relationship between rock and seismic. The analysis also provides a better understanding in terms of geology. The analysis has suggested that the reservoir can be properly identified by using the far-angle stack related attributes. This includes relative acoustic impedance (rAI) and an extended elastic impedance (EEI). Validation of the attributes to the well has shown that the two attributes can help identify and define the reservoir within the area better. And the newly identified target from the study resulted in a better well targeting.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"191 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123999929","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":"Numerical Investigations on the Doublet Huff and Puff Technology to Extract Heat from the Geothermal Reservoirs and Storing of CO2","authors":"Manojkumar Gudala, Zeeshan Tariq, B. Yan, Shuyu Sun","doi":"10.2523/iptc-22959-ea","DOIUrl":"https://doi.org/10.2523/iptc-22959-ea","url":null,"abstract":"\u0000 In this work, we studied the implementation of huff and puff technology to extract heat from the geothermal reservoir. Two-dimensional numerical investigations were carried out using a fully coupled two-phase thermo-hydro-mechanical model with dynamic rock and fluid properties. COMSOL Multiphysics (a finite element solver) was utilized to build the model. The CO2 geofluid is injected in a supercritical state in a water-saturated geothermal reservoir. The results were showing promising for the extraction of heat and storing of CO2. In the simulation model, we designed a well pair (two-vertical wells) system with two different operating perforations in the same well with huff and puff cycle operation, and this technology is named as Doublet Huff and Puff (DHP). Injection wells operating at the top of the formation and production wells are operating at the bottom. The injection well-1 and production well-1 are operating at same time (i.e., 2 years). During this period, injection well-2 and production well-2 are ideal, and injection well-1 and production well-1 are ideal while operating injection well-2 and production well-2. This process is continued till the whole reservoir is saturated with the injected CO2 and/or the reservoir temperature reaches 60 % (i.e., geothermal reservoir life) of its original temperature. The CO2 plume expanding throughout the reservoir effectively while extracting heat from the reservoir. The sensitivity of well distance, injection temperature, injection velocity, and perforation length on the production temperature was investigated. The production temperature stays stable and high for a long time and no influence on the production temperature. Thus, the proposed technique (DHP) can be implemented for sequestering large amounts of CO2 along with heat extraction in geothermal reservoirs.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121474343","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":"Acid-Induced Emulsion and Sludge Mitigation: A Lab Study","authors":"Luai Alhamad, Basil M. Alfakher, A. Al-Taq, Ali Alsalem","doi":"10.2523/iptc-22753-ea","DOIUrl":"https://doi.org/10.2523/iptc-22753-ea","url":null,"abstract":"\u0000 Acid matrix stimulation is a widely used method to improve well productivity by removing and/or bypassing damage in the near wellbore area and creating channels for hydrocarbon flow. Hydrochloric (HCl) and organic acids are commonly used to design fluid recipes utilized in these treatments. However, these acids can cause formation damage by forming stable emulsions and sludge upon contact with formation crude if the treatment and/or stimulation fluid are not designed carefully. It is well reported that acid in contact with crude oil can destabilize asphaltenes either by neutralizing asphaltene or dissolution of resins. Therefore, acid recipe chemical additives must be selected and examined carefully to ensure effective acidizing treatments.\u0000 In this study, the interaction of different HCl-based recipes with oil was investigated using different lab techniques and analysis including acid/oil separation tests, sludging tendency testing, and SARA analysis. The influence of several factors including acid concentration, acid type, and dissolved iron content were investigated. Experiments were conducted with varying acid blends, demulsifier and anti-sludge type and concentration. To simulate dissolving corrosion products by acids in downhole environment, ferric chloride was incorporated in acid recipes.\u0000 The results showed an increase in temperature enhanced emulsion/sludge breaking tendency. The addition of demulsifier/anti-sludge agents in acid recipes was necessary to avoid creating stable emulsions and sludge that can damage reservoir permeability. Higher amounts of dissolved iron in the acid solution resulted in a more stable emulsion and enhanced sludge formation. Asphaltene problematic oil, as determined from the asphaltene colloidal instability index, showed severe sludging tendency. Lastly, the use of HCl/organic acid blends may be necessary for some oil types to avoid formation of sludge.\u0000 This paper showcases a comprehensive testing method to mitigate formation damage from acidizing treatments. The testing can be expanded to design an acid stimulation fluid recipe to minimize acid-induced formation damage and maximize well productivity enhancement.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114801541","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":"Frequently asked Questions in the Interval Pressure Transient Test (IPTT) and what is Next with Deep Transient Test (DTT)","authors":"S. Daungkaew, A. Gisolf, D. Ling","doi":"10.2523/iptc-23050-ms","DOIUrl":"https://doi.org/10.2523/iptc-23050-ms","url":null,"abstract":"\u0000 The past few years have been challenging for the oil and gas industry. Many processes and operations have needed to adapt to lower oil and gas prices, caused in part by the COVID-19 pandemic. Understanding reservoir producibility and proving reserves are keys to generating a reservoir field development plan (FDP). However, the different processes to obtain such answers are strongly dependent on cost. The value of information is an extremely important criterion for operators to decide whether to proceed with their discoveries.\u0000 In an interval pressure transient test (IPTT), a formation tester is used to pump a fluid from a single point or small interval of the formation into the wellbore. Zones of interest can be isolated and tested separately zone by zone. Mud filtrate and reservoir fluids are pumped continuously using the downhole pump, and a downhole fluid analyzer (DFA) is used to monitor the fluid cleanup process. The post-pumping p pressure buildup can be analyzed in a similar manner to traditional well test analysis. Such IPTT have been available since 1980s; however, comparisons of IPTT to actual well tests and other permeability measurements were rarely published until the early 2000s. IPTT have been widely used in the past 20 years, especially in combination with dual packers, and more recently with single packers. Operation efficiency and safety have improved significantly. However, interpretation of the pressure transient obtained from an IPTT is not always well understood.\u0000 Frequently asked questions (FAQs) include the following: What is an IPTT or a vertical interference test (VIT)?How does an IPTT compare with other permeability measurements?What are the different scales of pressure transient data?How do we upscale zone permeability to an entire reservoir interval?What is next?\u0000 This paper will address these questions using both reservoir simulation and field data. The field examples are from different environments, ranging from shallow marine to turbidite to deepwater environments, with different fluid systems, such as black oil, heavy oil, waxy oil, gas, and gas condensate. Geographically, the field data include examples from South East Asia and the Middle East. Permeability obtained from pretests, IPTT, nuclear magnetic resonance (NMR), core analyses, and well testing will be compared.\u0000 Recently deep transient testing (DTT) has been introduced in the industry. With DTT, we can flow faster and longer than previously possible with formation testers, enabling pressure transient analysis in higher permeability and thicker formation. Further data quality improvements come from new, high-resolution gauges deployed with an intelligent wireline formation testing platform. This paper includes a review of the DTT method with several field examples.\u0000 Finally, the advantages and disadvantages of the different testing methods are discussed relative to the test objectives, with the intent to provide a cost-effective data selection method to ","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117136612","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":"Carbon Storage Leak Detection via Seismic FWI and RTM: Different Surveys Analysis","authors":"S. Amani","doi":"10.2523/iptc-22980-ms","DOIUrl":"https://doi.org/10.2523/iptc-22980-ms","url":null,"abstract":"\u0000 Marine seismic data processing is investigated to monitor possible leakages from the geological Carbon storage. Due to the high importance of storage permanence, a precise leakage monitoring strategy is crucial. Advanced seismic monitoring solutions should be used for this goal. The proficiency of these solutions for monitoring a Carbon storage leakage can be affected by shallower layers due to their structures, seismic wave attenuation, and leak size. Knowing the difficulty of this problem, we investigate the two popular seismic monitoring methods on Seismic data for monitoring Carbon leaks in different scenarios: Full Waveform Inversion (FWI) and Reverse-Time Migration (RTM).\u0000 Finding the best survey strategy for monitoring carbon leaks is also significant. So, the results of different survey strategies, including vertical seismic profiling (VSP), cross-well, and surface, are compared to demonstrate the pros and cons of each strategy.\u0000 The synthetic marine seismic data is calculated for different models, including Carbon storage and its leak. We used a set of realistic physical values for sedimentary rocks that are common for such a media. An elastic finite-difference time-domain scheme is used for the simulations. We applied FWI and RTM methods for monitoring Carbon Leaks using the seismic data. The FWI results demonstrate a good detection of the leakage areas that were clearer in the VSP survey than the others. Also, the performance of the FWI method was checked for different sizes of Carbon leaks. The results show the high capability of FWI as a solution to this problem. Besides, the RTM results show the high potential of the z-component of seismic data outperformed in showing the borders of the CO2 leakage. This point is more visible in the VSP results than in others. On the other side, the x-component of seismic data in the RTM results shows that it can demonstrate lateral reflectors better.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129143769","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":"Efficient Stimulate Long Horizontal Well of Carbonate by Accurately Acid Placement Technology: Case Study from Deep Carbonate Reservoir, Sichuan, China","authors":"Ren Jichuan, Guan Chencheng, Guo Jianchun, Dong‐Qing Bo, Zeng Jie, He Songgen, Wang Junfeng","doi":"10.2523/iptc-23003-ms","DOIUrl":"https://doi.org/10.2523/iptc-23003-ms","url":null,"abstract":"\u0000 The length of horizontal wells in deep carbonate reservoir (5000∼6000m) in Sichuan Basin of China has exceeded 2000 meters. Both generating acid-etched fractures and acidizing the dispersed pay-zone are the key to achieving optimal production. The complex conditions of multilayers make it difficult to use open hole packers, instead, sliding sleeves are used in liner completions. However, the layers show strong heterogeneity, which makes it difficult to realize efficient acid stimulation.\u0000 This paper presents a technology that stimulates such wells to achieve full acidizing of drilled reservoirs, and optimize the fracturing fluid system and acid-fracturing parameters to achieve longitudinal fracture penetration based on the sweet spot recognition.\u0000 Firstly, in order to describe reservoir characteristics and identify sweet spots along the well, an evaluation model was established based on the correlation evaluation parameters of the gas-bearing properties, petrophysical properties, natural fractures, and fracability. The high sweet spot coefficient (HSSC) section and low sweet spot coefficient (LSSC) section were recognized. Then, based on the section classification and the optimal fracture spacing, the position of sliding sleeves is optimized. Sleeves were mainly set at the highest points of sweet spot coefficients in the nearby section.\u0000 For different sections, different acid stimulation strategies are proposed respectively. For the HSSC, it is necessary to increase the coverage of acid in the wellbore to realize the efficient acid stimulation of sweet spots alone the wellbore. However, the LSSC sections are mainly caused by the deflection of well, creating artificial fractures and making fractures propagate along the height direction into TL43-3 are needed.\u0000 In HSSC sections, the acid coverage increases with the increase of acid volume and injection rate, and it is preferred to use temporary plugging to obtain the wide acid coverage when half of the acid is pumped making the two fractures obtain efficient stimulation with the acid absorption ratio of 1.47 and acid coverage of 207.1m\u0000 In LSSC sections, it is still difficult to make artificial fracture break through the upper and lower layers by only use gelled acid even if the acid injection rate is greatly increased. A high viscosity fluid was introduced in acid stimulation treatments could make artificial fracture vertical propagating to break through the upper layers of 16 MPa stress difference with injection rate ≥ 5 m3/min and volume of 100m3.\u0000 The productivity of 5 applicated wells increased 66.28%, which proved that the stimulation strategies of HSSC sections and LSSC sections are successful.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"362 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125654592","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":"Particulate Wellbore Fluid Strengthening Methodology. Design and Application in an Offshore Vietnam Severely Depleted Sand Reservoir","authors":"Dourado Motta Marcelo, Huynh Son, M. Yoon, Chau Tran Duc Minh, Thai Le Quoc, Hung Pham Quoc, Dung Le Vu, Que Nguyen Van, Thierry Batot, Tuan Lam Minh","doi":"10.2523/iptc-22786-ms","DOIUrl":"https://doi.org/10.2523/iptc-22786-ms","url":null,"abstract":"\u0000 In the mature Cuu Long basin, offshore Vietnam, the dynamic reservoir model projected the pore pressure's depletion as high as 4,723psi countering virgin pressure (up to 8,500psi) for one particular \"gas-condensate\" well. Coupling with expected deviation of 38° inclination and un-disturbed temperature of up to 170°C, posed a considerable challenge for this well.\u0000 High bottom hole pressures can potentially exceed the formation fracture gradient resulting in tensile failures and well fractures. Wellbore strengthening (WBS) techniques are used to allowing depleted reservoir formations to be drilled with lower risk. Hoop stressing is a method to increase wellbore stress so that a controlled tensile failure occurs at an elevated wellbore pressure; thereby, strengthening and expanding the wellbore stability window. This method uses material introduced into the mud system to seal off induced fractures and in effect, increase and maintain the hoop stress in the wellbore when drilling. The inherent challenges include understanding the effect of depletion to the change of induced fracture pressure and fracture width (fracture aperture) also Rock elastic properties (Young's Modulus, Poisson Ratio), well design (well architecture, hydraulic), testing, and validating wellbore strengthening by the material.\u0000 A proprietary software was used to model a probabilistic distribution of the potential induced fractures given the in-situ conditions. Modelling involved using location-specific geo-mechanical information, planned drilling conditions, and parametric sensitivity to predict induced-fracture widths. Fracture widths from 500 to 750μ were determined based on modelling and used as the baseline for testing validation.\u0000 Testing was performed using a Fully Automated Advanced Slot Tester (FAAST) to optimize WBS packages to seal off the predicted fracture widths with testing pressures reaching 4,000psi. A range of slot sizes were tested to evaluate and validate performance of various particulate WBS packages, with focus on 500 and 750μ sizes. The final optimized package included both proven sized strengthening material as well as finer bridging material.\u0000 Field execution of the WBS techniques consisted of introducing and maintenance of the optimized package to the drilling fluid system on a continuous basis while drilling different hole sizes (12-1/4″, 8-1/2″, or 6″ as contingent section) through the depleted reservoirs through the usage of concentrated engineered pre-mixed pills in reserve to optimize logistics. Replenishment of active concentrations was carefully monitored to counter the removal of the material by the surface solids control equipment as well as the material consumption in the induced fractures.\u0000 Drilling the reservoir section with the wellbore strengthening and bridging technique was successful. Implementing this strategy delivered a stable wellbore while drilling and the liner or casing run to bottom successfully. Field measured pore pressures p","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115253269","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":"Co-Evolution Law and Control Technology of Corrosion and Scaling in Water Injection Wells of a Middle East Carbonate Oilfield","authors":"Z. Ye, Guan Wang, Xiang Zhou, Limin Zhao, Weidong Jiang, R. Yi, Xiaodong Cui, Z. Qiu, Zhiwen Yang, Yingfeng Chen, K. Li","doi":"10.2523/iptc-22928-ms","DOIUrl":"https://doi.org/10.2523/iptc-22928-ms","url":null,"abstract":"\u0000 In order to compensate formation pressure and maintain oil production, a carbonate oilfield in the Middle East adopts water flood development. The injected water exhibits the feature of high salinity and high content of chloride, high content of H2S, and high content of scaling ion. As a result, severe corrosion perforation and plugging were encountered in less than two years, which seriously affects the normal water injection and production of the oilfield.\u0000 This paper aims to find out the main controlling factors and co-evolution law of corrosion and scaling, and propose the prevention strategy. The composition of the scale samples is firstly analyzed by combustion method, XRD and atomic absorption spectrometry, and then the main controlling factors of corrosion and scaling are experimentally clarified. On this basis, immersion experiments at different times are further carried out to reveal the evolution of corrosion and scaling in injectors at different depths.\u0000 The results show that temperature, salinity (mainly Cl-), total sulfur content, and sulfate reducing bacteria (SRB) are the main factors controlling corrosion and scaling, and there is a synergistic effect among them. Temperature and sulfide have a promoting effect on uniform corrosion and scaling, while the salinity in the range of 110g/L-180g/L has an inhibition effect, but has a promoting effect on localized corrosion under deposits; a small amount of SRB can still propagate rapidly under deposits, aggravating the localized corrosion. Along the wellbore profile from top to bottom, the uniform corrosion rate and scaling amount increase but the localized corrosion rate decreases, which indicates that the high risk of localized corrosion perforation in the middle and upper part of the wellbore, as compared to the lower part. It is consistent with the actual corrosion perforation law of water injection wells. The co-evolution mechanism of corrosion and scaling is a synergistic process of three factors: lower uniform corrosion rate under high salinity + sulfide-induced local corrosion initiation + SRB enrichment under deposits and acidification autocatalysis due to Cl- migration. Finally, corrosion and scale control measures were taken by deep desulfurization and adding corrosion inhibitor. This work provides useful practical experience for preventing corrosion and scale formation of high salinity injector in carbonate oilfield.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121754737","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}