Day 1 Mon, February 12, 2024最新文献

{"title":"Breaking the Chain, Novel Use of Adaptive Model Approach for Reservoir Modelling Reduces Time Duration of Project and Improves Collaboration","authors":"A. R. Thompson, C. E. Z. Bolivar","doi":"10.2523/iptc-23935-ms","DOIUrl":"https://doi.org/10.2523/iptc-23935-ms","url":null,"abstract":"\u0000 This paper details how the reservoir modelling workflow can be accelerated, and uncertainty reduced even for challenging Green Field prospects by constructing multiple small fit for purpose integrated adaptive models instead of just one all-encompassing model.\u0000 Adaptive models are models built with a single purpose as compared to more conventional reservoir models which are designed to be flexible and be used for multiple purposes. By only having a single task, these adaptive models can be built more quickly and since they are used as tool, not the product, they do not need to be reviewed. Multiple different adaptive models are built to handle different questions ranging from production data QC, different facies models going through to local history matches. As the study progresses, these adaptive models can be combined to consider multiple components and their influence on each other to ensure compatibility and to possibly feed information to the modeling effort for the full field model. As the project finalizes, these adaptive models work like jigsaw pieces to come together to create the finalized picture/model.\u0000 In the application of adaptive models within an integrated reservoir study, the most obvious benefit is being able to complete the static and dynamic aspects of the model building in parallel and subsequently be able to move more quickly to the deployment of the model for placing wells. Another key benefit was that it was possible to evaluate and defend new concepts or methods in reservoir modeling. Integrating new components into an existing modeling doctrine is challenging as significant time has to be expended and this has to be justified in advance of knowing the impact of the new item. With adaptive models, it is possible to evaluate out of doctrine ideas in parallel and off critical path. If the results are positive, the adaptive model is available to justify the benefit of the change and to also act as a comparison to the result following the doctrine.\u0000 This innovative workflow enables more efficient working by reducing the number of items on the critical path while simultaneously improving integration by enabling static and dynamic data to be integrated before the static model is finalized. In addition, this approach is a driver for innovation as it enables new ideas to be evaluated more rapidly and without having to impact the critical path of the project.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527802","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":"Annulus Testing as the Integrity Management Method for Steel-Reinforced Thermoplastic Pipe","authors":"K. Kovalenko","doi":"10.2523/iptc-24549-ms","DOIUrl":"https://doi.org/10.2523/iptc-24549-ms","url":null,"abstract":"\u0000 Decarbonization efforts by the energy industry have driven a strong focus on implementing corrosion-resistant non-metallic pipe technologies. Reinforced Thermoplastic Pipes (RTP) comprise a popular family of pipe products that combine high-pressure ratings with the benefits of spoolable products. Due to their multi-layered structure, RTP pipe products face challenges when operators try to employ traditional non-destructive evaluation (NDE) technologies for inspection and integrity verification. This creates a unique opportunity for RTP pipe manufacturers and pipeline operators to employ innovative inspection and maintenance practices.\u0000 Construction damage is statistically the most common cause of failures in RTP pipeline systems. RTP pipes typically include an inner polymer liner, an intermediate reinforcement layer, and an outer polymer shield. The role of the shield is to protect the reinforcement material from external environmental elements such as soil and groundwater. Construction damage that involves only the external pipe shield and does not involve the pipe reinforcement is challenging to detect. If left undetected, such damage may lead to the deterioration of the reinforcement material over time, potentially resulting in a loss of containment. Some RTP pipe products, including Flexible Steel-reinforced Pipe (FSP), have a built-in annulus space between the liner and the shield. This inherent feature allows for the introduction of an annulus test for a pipeline constructed from the FSP. The annulus test is a pneumatic pressure test that confirms the integrity of the pipe shield at different stages of the pipeline life cycle.\u0000 Annulus testing performed during pipeline operation or maintenance offers an excellent way to verify the nonmetallic pipeline integrity and detect external damage that may have occurred, for example, due to third-party intervention. Once external pipe damage is detected, the operator can take steps to repair the pipeline and prevent a potential loss of containment. While such testing is well-known in the offshore pipeline industry, it has not been widely used in composite onshore pipeline applications.\u0000 Modern pipeline design, construction, and integrity management standards are beginning to acknowledge and incorporate RTP pipe products and associated best practices. In 2022, the newly published API Recommended Practice 15SA named annulus testing as a method for integrity verification of spoolable reinforced line pipe products. This method has become an essential part of Preventative Maintenance and Inspection Programs for composite pipelines. This publication explains how the annulus testing method makes composite pipelines safer and improves their long-term performance.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"76 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528199","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":"Digital Solution for Well Surveillance in Stacked Reservoirs with Near-Critical Fluid Systems","authors":"K. Mogensen, C. Mata, S. Samajpati, P. Cremades, J. E. L. Uribe, M. Al Zaabi","doi":"10.2523/iptc-23912-ms","DOIUrl":"https://doi.org/10.2523/iptc-23912-ms","url":null,"abstract":"\u0000 Fully compositional integrated asset models (FC-IAM) are being deployed for an increasing number of fields in the company's portfolio. Field A described in this work comprises four stacked reservoirs, each containing a near-critical fluid system with significant compositional depth gradient. Augmenting the FC-IAM with high-frequency sensor data as well as proprietary tools to actively monitor well performance helps identify and pursue opportunities to maximize the oil production rate from the field, subject to several system constraints.\u0000 Fluid properties were modelled with a cubic equation of state tuned to laboratory data to address some key challenges: Near-critical fluid systems giving rise to compositional variation versus depth.Injection of produced gas that develops multi-contact miscibility with the original reservoir fluids.Blending of fluids at surface from four stacked reservoirs.Operational requirement to maintain the bottom-hole pressure above saturation pressure.Validation of raw well test data before shrinkage correction (line conditions).\u0000 Compositional surface network models are run automatically on hourly basis and compared against real-time data. A surveillance algorithm identifies opportunities and assigns them to well owners. Activities are managed through a high-level tracking and value-capture system.\u0000 The asset team is consistently maintaining the well and surface network models assisted by the digital solution. The surveillance automation engine creates a feedback loop with the engineers which ensures that the models are of sufficient quality for production optimization. Models reproduce the actual oil and gas produced rates within the accepted accuracy range and are used routinely in optimization scenarios. The surface network model is also run in transient mode to study and optimize flow in two large subsea multiphase pipelines. Total value generation from implementation of the complete framework therefore exceeds expectation based on the steady-state production gain. The intangible value associated to reducing engineers’ workload, better data accessibility, HS&E and efficiency of operations has set a strong foundation for the strategy of the company to grow its enterprise value through increased volume and cost reduction.\u0000 Implementation of a compositional model framework is still uncommon as most integrated asset models rely on a black-oil formulation for the fluid property description. Near-critical fluid systems undergoing miscible gas injection add an additional layer of complexity in terms of modeling and surveillance efforts. Real-time data have proven indispensable for keeping the IAM up to date and for identifying opportunities for optimizing the production.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527609","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 Innovative Approach to Real-Time NMR Permeability Calibration Utilizing Azimuthally Oriented Formation Testing While Drilling","authors":"M. Fouda, A. Taher, O. Ramadan, A. Binghaith, M. Saad","doi":"10.2523/iptc-23833-ms","DOIUrl":"https://doi.org/10.2523/iptc-23833-ms","url":null,"abstract":"\u0000 Evaluating lateral variations of permeability is usually attempted using conventional logging tools and relying on field-specific porosity-permeability relationships. These transforms are generally built on core analysis and previous reservoir knowledge. Many Carbonate reservoirs given their complex pore structure, however, exhibit poor relationship between porosity & permeability and would hence need other more sophisticated methodologies and workflows to evaluate permeability. Nuclear magnetic resonance (NMR) is a well-known measurement that can provide indications of pore size in heterogeneous reservoirs and can hence be used for permeability evaluation. Formation testing while drilling (FTWD) can be used for mobility estimation while drilling. This paper presents the benefits of integrating logging-while-drilling (LWD) azimuthally oriented FTWD and NMR to reliably evaluate lateral permeability variations in horizontal wells.\u0000 NMR log-derived permeability is achieved by analyzing the T1 or T2 distributions and applying a cutoff differentiating pore size variation. The classification of the pore size distribution is input into established NMR permeability equations. These equations, however, have coefficients that need to be determined. The optimum irreducible water saturation cutoff as well as the permeability equation coefficients are ideally established with core analysis techniques. In horizontal wells across heterogeneous reservoirs having no representative core plugs formation testing can be used to help establish these parameters. Formation tester tools have been traditionally utilized to acquire a single pressure measurement and mobility calculation at any specified depth station. LWD testers, however, can be oriented around the wellbore to acquire several pressure and mobility values at different orientations. After investigating real time azimuthal images for bed boundaries and azimuthal variations, specific orientations of the formation tester can be selected to provide the most representative.\u0000 LWD NMR real-time permeability indicators showed pore size variations at the same porosity range. FTWD mobility data has enabled normalization of NMR permeability curves by providing calibration points at the test stations. The azimuthal orientation of FTWD tests was selected using LWD real time density and resistivity images to ensure the FTWD probe is not pointing to a tight bed boundary. High-resolution resistivity images from memory data provided an understanding to the mechanism causing variation in the azimuthal permeability profile. Combination of oriented FTWD and NMR permeability indicators aided real-time well-placement decisions and helped placing the wells into the most permeable zones. This paper presents an innovative approach for evaluating real-time permeability utilizing oriented LWD formation-testing mobility data with NMR permeability indicators.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"513 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528382","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":"Conveyance Options for Pipe Recovery in a Stuck Drill Pipe Scenario in Horizontal Wells","authors":"S. Kishore, J. Woods, D. Engel, K. Batyrkhanov","doi":"10.2523/iptc-23932-ms","DOIUrl":"https://doi.org/10.2523/iptc-23932-ms","url":null,"abstract":"\u0000 Recovery of stuck drill pipe is a challenge in deep horizontal wells. Typically, in a vertical or slightly deviated well, after attempts have been made for recovery of stuck drill pipe by working the pipe, the option to convey the pipe recovery tools with electric line is relatively simple due to gravity descent. However, in horizontal wells, the options to convey the recovery tools require electric line using tractor or pump-down techniques; alternatively, coiled tubing can be used for conveyance. Our study evaluates these three methods and compares the efficiency and effectiveness of these conveyance methodologies.\u0000 The application of these solutions each have their own advantages and some disadvantages, especially as the access within the drill pipe can be limited due to the presence of various types of restrictions such as debris or the variable diameter inside the pipe, which usually has an \"internal upset\" on the connections. These restrictions combined with the potential nonexistence of circulation will affect the maximum reach for the conveyance methods to differing degrees. The ability to reach the target may be limited in extended reach wells and the target cutting depth may not be feasible with some conveyance options. The presence of radioactive sources in the drilling assembly may also complicate the pipe recovery operation.\u0000 Three different conveyance options to perform the pipe recovery operation used on different operations in the Middle East are documented: e-line tractor, e-line pump-down, and coiled tubing conveyance. We compare the options and evaluate the results from the three conveyance methods for the pipe recovery tools to sever the stuck drill pipe. Each of the methodologies can be effective, and the ideal application depends on the existing downhole conditions present at the point the drill pipe becomes stuck.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"72 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527921","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 Production and Cost Optimization in a Remote Carbonate Oilfield through a Standalone Waterflooding System: An Oman North Case Study","authors":"A. A. Al-Mamari, M. A. Al-Ajmi, H. N. Al-Omeiri","doi":"10.2523/iptc-23926-ms","DOIUrl":"https://doi.org/10.2523/iptc-23926-ms","url":null,"abstract":"\u0000 Oxy's Oman North concession, a remote carbonate oilfield with a gas cap, initially produced under natural depletion, but production declined rapidly due to low reservoir pressure and a weak edge aquifer.\u0000 To address this issue, waterflooding was deemed necessary. However, the field's location, which was approximately 50 km away from the main production station, posed a challenge because it would require considerable time and cost to install water injection facilities that are connected to the main station and provide the required produced water for injection. To overcome this challenge, a standalone system was designed with surface pumps for water injection. The project was executed within a year at a cost that was about 25% of constructing a water injection header from the station.\u0000 The system's design included horizontal injectors that were aligned to support horizontal oil producers and prevent the encroachment of the gas cap further downdip. Injection optimization and redistribution of water among the injectors were strategies for maintaining high production and helped to control costs, as they ensured that no injected water or energy was wasted without a return of oil. For example, voidage replacement ratio and diagnostic plots were produced on a monthly basis to monitor the injection performance. The surface network was also optimized using Prosper and GAP modeling tools along with day-to-day monitoring. Wells were choked and opened to maximize production for the entire network. The implementation of these best practices resulted in a significant acceleration of field production. Within the first 18 months, production tripled, and then reached more than five times pre-waterflood rates by 2023.\u0000 This paper presents an innovative method within the industry that effectively increases production while being cost-efficient. It introduces a pioneering approach that revolutionized production processes, achieved remarkable results, and ensured significant growth in production capacity.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"29 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528183","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":"Legacy Wells Screening Method for Potential CO2 Storage Sites","authors":"H. C. Enriquez, H. Dick, C. Holloway, R. Salter","doi":"10.2523/iptc-24131-ms","DOIUrl":"https://doi.org/10.2523/iptc-24131-ms","url":null,"abstract":"\u0000 The authors developed a legacy-wells screening method for potential CO2 storage sites. The screening method enables project teams to evaluate qualitatively, in a consistent manner, the legacy wells risks at potential Carbon Capture and Sequestration (CCS) candidate sites. It does so by identifying the legacy wells current status, preliminary corrective action requirements and associated risks based on a specific data set that can be extracted from public well records.\u0000 For CO2 storage sites, legacy wells are existing wells that are located within the predicted CO2 plume and/or pressure front area. When assessing the feasibility of potential storage site candidates, legacy wells risk is an important variable for ranking the feasibility of potential locations against each other. Legacy wells risk is a result of not only the number of wells but also their leakage potential and the complexity of the corrective actions required. Often, only legacy well density (number of wells per squared kilometer) is evaluated, disregarding elements of risk such as well status, well age, well architecture, well mechanical status, etc.; if or when a risk level is assigned to the wells, it is done so in a subjective manner. A systematic method will be illustrated in this paper that evaluates existing well conditions and intervention requirements to evaluate legacy wells risk for potential storage sites.\u0000 To evaluate the legacy wells risk beyond only well density and to eliminate the subjectivity of screening, the authors used a method based on a ranking system that considers a few, critical, well characteristics to assign a risk score that can then be compared equally between potential locations. The ranking system assigns risk scores to legacy wells based on the availability and quality of well data, and in parallel the complexity and risks of each potential remediation or corrective action.\u0000 The paper will present a case study of a CCS site feasibility study where the workflow was applied to provide a consistent approach to legacy well assessment and qualitative risk evaluation for potential storage sites. Future CCS operators will benefit from this approach to improve decision making before selecting and moving forward with a storage site.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"27 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527615","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":"Completion Philosophy Rejuvenation to Maximize Well Potential in Challenging Sour HPHT North Kuwait Jurassic Gas Fields","authors":"M. Abdel-Basset, Mohamed Al-Sharad, M. Al-Arouj, T. Bloushi, M. Al-Mutawa, M. Al-ajmi","doi":"10.2523/iptc-23774-ms","DOIUrl":"https://doi.org/10.2523/iptc-23774-ms","url":null,"abstract":"\u0000 It always remains a big question, what is the best way to complete a well for maximum potential? Selecting proper well completion is critical to overcome reservoir challenges and ensure efficient stimulation treatments and well intervention specially in challenging deep highly deviated wells targeting complex high heterogenous HPHT conventional and unconventional tight carbonate gas reservoirs such as North Kuwait Jurassic gas fields (NK JGF). This paper will demonstrate the added value, experience, challenges and lessons learned of completion strategy rejuvenation and paradigm shift journey of NK JGF's wells completion till landing to a combination of three main completion schemes based on structured selection criteria. This is led by integrated team to enhance overall well production potential, overcome reservoir and intervention operations challenges, and early production delivery to achieve asset strategic production target.\u0000 The Jurassic gas fields produces mainly from deep HPHT, conventional and unconventional tight carbonate reservoirs. The recovery from such complex heterogeneous reservoirs is extremely challenging if conventional development strategies are applied. Due to the high reservoir tightness, permeability contrast among different flow units and dual permeability effect (matrix and natural fractures), well productivity potential significantly depends on the effectiveness of subsequent stimulation treatments of such complex heterogeneous reservoir to improve well productivity and connect the natural fractures.\u0000 Selecting proper well completion is critical to overcome such reservoir challenges and ensure efficient acid stimulation treatments of such complex formations that need convenient diversion mechanism during the stimulation to enhance the productivity of each individual reservoir layer and enable future flexibility of selective re-stimulation and reservoir management.\u0000 Based on solid understanding and field experience, the NK JGF asset team has applied a step change in completion strategy from initial legacy 3.5\" tubing and 5\" cemented liner at early development phase, then 4.5\" monobore cemented completion, to recently 4.5\" openhole multistage completion until landing on combination of these three main completion schemes based on structured selection criteria considering integration of all subsurface domains and operation teams.\u0000 Improving the completion efficiency is continuously helping to overcome the NK JGF's reservoirs complexity, improve the overall well potential and associated cost in addition to fast track well delivery to production to meet asset production target.\u0000 Based on gained experience, an integrated protocol for well completion selection, staging design and installation procedures of multistage completion workflow has been built by the integrated multidisciplinary team to ensure standard process across fields which can be used for application in other fields. This paper describes the learnings of the Jur","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"29 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528009","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 In-Situ Stress Evolution and Its Impact on Infill Well Fractures Propagation- A Case Study from China","authors":"Xiaoguang Wang, Qingxiang. Wu, Zhibin Jiang, Dan. Xie, Wei. Zhou, Chuanchuan. Qian, Liming. Lian, Jie. Wang, Zheng. Li, Liming. Qu, Xingning. Huang","doi":"10.2523/iptc-23722-ms","DOIUrl":"https://doi.org/10.2523/iptc-23722-ms","url":null,"abstract":"\u0000 Hydraulic fracturing of horizontal wells is an effective development mode for low-permeability reservoirs, while new drilling can enhance reservoir recovery. The drilling, fracturing, and production processes all induce changes in reservoir stress, affecting the infill wells’ fracture design. Adoption of finite element-based discontinuous discrete fracture numerical method. The extension of wellbore and fracture is described by dynamic mesh technology during drilling and fracturing, and the discontinuous discrete fracture model can be computed by using a conventional finite element mesh, which can be perfectly matched with the discrete fracture model, so as to realize the integrated numerical simulation of drilling-fracturing-production. Use the construction of infill wells in low-permeability reservoirs in Area 8 as an example, the integrated simulation of drilling-fracturing-production is carried out for the wells to be constructed in the encrypted well area, and the maximization of the exploitation economy of the well area guides the optimization of the infill wells’ fracturing. The simulation results show that the long-term production process of the old well reduces the formation pressure and ground stress in the encrypted well area, and the direction of the maximum horizontal principal stress is deflected. Considering the influence of the old well production, the drilling fluid density during the drilling of the encrypted well can no longer be designed using the original formation pressure profile. With the drilling fluid column pressure not greater than the minimum horizontal principal stress at this stage, the direction of maximum horizontal principal stress around the encrypted well is further deflected after the wellbore is drilled open, causing the initial expansion direction of the fracture to be deflected along the wellbore; injecting water to boost the pressure of the old well prior to the fracturing of the encrypted well can improve the fracturing effect of the encrypted well. The established numerical method can realize the simulation of reservoir stress evolution in the whole process of drilling-fracturing-production and the integrated numerical simulation of fracturing-production, which can optimize the design of fracturing in infill wells and improve the single-well production.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"9 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528214","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 New Automated Carrying Capacity Index Model Optimizes Hole Cleaning Efficiency and Rate of Penetration by Applying Machine Learning Technique","authors":"Mohammed Murif Al-Rubaii محمد مريف الربعي","doi":"10.2523/iptc-23896-ms","DOIUrl":"https://doi.org/10.2523/iptc-23896-ms","url":null,"abstract":"\u0000 Hole cleaning is a major factor to drill hydrocarbon wells in safe and competent manner with cost effectiveness. Hole cleaning contributes to minimizing drilling troubles such as stuck pipe incidents and avoid well loss if hole cleaning was not managed properly. Ensuring adequate hole cleaning efficiency will help drill fast with smooth rate of penetration (ROP) with desired drill cuttings transport. In this paper, the development of a new real time hole cleaning model to evaluate and monitor hole cleaning effectiveness while drilling and ensure drilling efficiency optimization with high quality and economics in safe and environmental manner. Moreover, Artificial intelligence (AI) tool that is artificial neural network (ANN) was applied for confirming and validating selected parameter of model to show similar real time profile.\u0000 The methodology to develop real time hole cleaning model is based on carrying capacity index that was developed earlier only for vertical wells. The original carrying capacity index will be optimized and enhanced to consider other mechanical drilling parameters and drilling fluid theological properties. The model will account the wellbore inclination, average hole cleaning annular, cuttings, hydraulics velocities based on the impact of cuttings accumulation, jetting drill bit nozzles, mud rheology, gravity, ROP, temperatures, and pressures and altered drilling fluid viscosities with rig and bit hydraulics. Many offset mechanical drilling parameters and drilling fluid properties were collected for studying the influences and relationships on hole cleaning efficiency and rate of penetration. The developed model will be developed and fed by real time values of sensors of drilling rig and generate real time profile of hole cleaning efficiency for evaluating, monitoring, and improving ROP with allowing immediate intervention by drilling team while drilling operations. The model can be used in panning phase and different drilling scenarios to have an evident imagination of downhole cleaning effectiveness. On the other hand, ANN application was run by selecting inputs of mud pump flow rate (Q), standpipe pressure (SPP), rate of penetration (ROP), plastic viscosity (PV), yield point (YP), mud weight (MW) and low shared yield point (LSYP) were collected and used of total number 5563 real time readings.\u0000 The newly developed real time model was applied in the field in vertical and directional hole sections with water base mud and oil base mud to improve rate of penetration (ROP) and evaluate mud theological properties capability to have effective drill cuttings transport. The drilling efficiency was obtained, and ROP improved by 55%. While ANN model showed regressions (R2) 0.961 & 0.956 with absolute average percentage error (AAPE) 2.595 & 2.621 for training and testing validations respectively. The real time model was applied as well in real time offset wells parameters and confirm the importance of real time hole cleaning model.","PeriodicalId":519056,"journal":{"name":"Day 1 Mon, February 12, 2024","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140528167","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}