Day 2 Thu, February 22, 2024最新文献

{"title":"Maximizing Slim Hole Well Deliverability: First Installation of 3.5\" Alternate Path Open Hole Screen in Indonesia and Implementation of Erosional Velocity Analysis","authors":"S. Herputra, J. Sare, R. Binilang, B. Pande, M. Sentunata, M. Rossi, P. A. Merati, L. H. Hosen, N. Kurniawan","doi":"10.2118/217910-ms","DOIUrl":"https://doi.org/10.2118/217910-ms","url":null,"abstract":"\u0000 This paper presents the case history of a successful application of slim open hole completion as a cost-effective solution for sand control in a subsea gas well and the optimization of production by implementing erosion velocity analysis method beyond conventional erosion limitation set by API 14RP standard.\u0000 Soon after production start-up, solid production and subsequent reduction in production rate were observed in subsea gas wells at \"B\" field through a shape memory polymer screen completion. The company thus decided to perform a workover, sidetrack the well from 9-5/8\" casing and recomplete the well in 6\" × 8\" Open Hole using open hole gravel pack. Due to the presence of shale, the well was drilled with oil-based drill-in fluid (DIF) to ensure open hole integrity. The DIF was displaced to low-solid oil-based mud prior to running screens and later displaced to water-based once the screen was on depth prior to pumping gravel pack fluid. In order to achieve efficient fluid displacement, thorough simulation and analysis were run. For sand control strategy, open hole alternate path system was selected in combination with Visco-elastic Surfactant (VES) gravel carrier technology to allow bypassing potential sand bridges in the annulus. Extensive fluid compatibility tests were also performed in the field to avoid incompatibility during each phase of the operation. Downhole gauges were installed in drill pipe and wash pipes to allow post-job analysis and confirm packing efficiency post-gravel pack. They also enabled identification of downhole events during job execution. The result of the analysis was then used as lesson learned for subsequent well operation.\u0000 After gravel pack execution in the first well, post-job downhole gauge analysis showed premature fracture occurred during gravel packing which caused some proppant to go into the fracture. Further analysis showed that the lower section of the screens could have been plugged prior to gravel-packing, which contributed to high friction during the gravel pack which led to premature fracture. Several changes were proposed for the second well. One of them was to perform open hole displacement prior to setting packer to minimize the amount of fluid going through the screens during displacement. Gel loading and proppant concentration were also optimized to promote bridging within the open hole, activating the shunt tubes. The second well was gravel packed successfully with a positive screen-out indication. Downhole gauge data analysis also showed very little indication of screen plugging compared to the first well and good packing indication across the screen annular.\u0000 Due to slim hole, there was a concern regarding erosion limitation of the completion accessories if the well is to be produced as per target rate. As a solution, an in-house erosion velocity simulation analysis was proposed. This more advanced analysis was based on fluid dynamics simulation and capable of predicting erosion more accurat","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"123 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527706","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":"How High-Resolution Visualisations and Quantifications Gave Insight into Damaging Mechanisms and Treatment Fluid Performance in Omani Carbonate Reservoirs","authors":"J. Green, I. Patey, L. Wright, P. Zonjee, S. Al Hosni, O. Al Mamari","doi":"10.2118/217883-ms","DOIUrl":"https://doi.org/10.2118/217883-ms","url":null,"abstract":"\u0000 A study was carried out to examine Formation Damage mechanisms caused by drilling and completion fluids in onshore wells in Oman. A specific understanding of what caused any damage was important, as this data would be used to help select treatment fluid options and assess their suitability. Two phases of corefloods looked at the compatibility of drilling mud and displacement fluid with reservoir core, and two further phases considered a range of treatment options. Treatment fluids included different strengths of hydrochloric acid, with and without solvent. The initial phases showed moderate to very high levels of permeability reduction, predominantly caused by the nature of the drilling mud-cakes and incomplete clean-up during drawdown. 15% HCl was successful in removing much of the operational fluid damage but was typically not forming wormholes. Including a solvent seemed to aid in wormhole development but left some of the operational fluid damage at the wellbore. Using only traditional metrics such as permeability measurement, filtrate loss volumes, and electron microscopy, it was difficult to see differences between the treatment options; when adding in the visualisations and quantifications there were clear variances in behaviour. Taking this integrated approach was therefore key to gaining a proper understanding of damaging mechanisms, how they could be removed or bypassed, and whether treatment fluids worked as intended.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"1134 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527711","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":"Sparse Subsurface Sensor Signal Estimation for Formation Damage Assessment via a Smart Orthogonal Matching Pursuit","authors":"Abdallah Al Shehri, K. Katterbauer, Ali Yousef","doi":"10.2118/217893-ms","DOIUrl":"https://doi.org/10.2118/217893-ms","url":null,"abstract":"\u0000 Carbonate reservoirs exhibit water front movement through microfractures, corridors, and related fracture channels (larger than 5 mm in size) as well as the matrix structure, exhibiting generally complex flow patterns. It is crucial to identify the water front motions and fracture channels inside the flow corridors in order to maximize sweep effectiveness and boost hydrocarbon recovery. Here, we provide a new AI-driven orthogonal matching pursuit (OMP) technique for detecting water front movement in carbonate reservoirs determining possible formation damages that impact the flow within the formation. In order to identify and extract possible fracture channels, the technique first applies a combined artificial intelligence (AI) AI-OMP methodology. After that, a deep learning strategy is used to estimate the water saturation patterns in the fracture channels and assess the resulting formation damage.\u0000 To identify the fracture channels affecting each particular sensor, the OMP uses the sparse fracture to sensor correlation. The deep learning approach then makes use of the fracture channel estimations to evaluate the patterns of the water front. On a synthetic fracture carbonate reservoir box model with a complicated fracture system, we tested the AI-OMP framework. In order to improve reservoir monitoring, essential reservoir characteristics (such as temperature, pressure, pH, and other chemical parameters) will be sensed using Fracture Robots (FracBots, around 5mm in size). A wireless micro-sensor network is used in this technology to map and track fracture channels in both conventional and unconventional reservoirs. Since magnetic induction (MI)-based communication demonstrates extremely stable and continuous channel conditions with a suitable communication range inside an oil reservoir environment, the system enables wireless network connectivity via MI-based communication. The base station layer and the layer for FracBot nodes make up the two levels of the network's system architecture. To capture data that is impacted by variations in water saturation, many subsurface FracBot sensors are injected in the formation fracture channels. To enhance sensor measurement data quality and better track penetrating water fronts, the sensor placement in the reservoir formation can be modified. They spread out in the fracture channels and move with the injected fluids as they begin to sense the conditions of the environment including formation damage that impact the waterfront movements. They then communicate the data, including their location coordinates, among one another before sending it in a multi-hop fashion to the base station installed inside the wellbore. An aboveground gateway and a large antenna make up the base station layer. To be processed further, the FracBots network data is sent to the control center via an aboveground gateway.\u0000 In properly identifying the fracture channels and the saturation pattern in the subsurface reservoir, the findings","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"66 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527566","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":"Enhanced Injectivity Using Diversion Technology on Hydraulic Fracturing Jobs in Los Llanos Basin","authors":"A. Quintero, E. Sepúlveda, J. Reina, J. Bahamón","doi":"10.2118/217907-ms","DOIUrl":"https://doi.org/10.2118/217907-ms","url":null,"abstract":"\u0000 Conventional fracturing requires isolating one interval or a set of intervals hydrostatically to ensure the proper placement of proppant mass. This process involves considering various factors such as perforated length, formation permeability, and fluid leak-off performance to define the success of a hydraulic fracture. As the interval size increases, proppant placement becomes more challenging due to heightened fluid leak-off, incompetent fracture width, and increased hydraulic horsepower requirements.\u0000 To reduce workover rig hours and enhance efficiency in hydraulic fracturing operations, there is a need for added versatility. This paper aims to address this requirement by introducing a state-of-the-art particulate diverter in the Los Llanos basin; the implementation of this latest-generation diverter has proven instrumental in achieving operational goals.\u0000 Efforts to minimize workover rig hours align with current efficiency initiatives in hydraulic fracturing. The versatility introduced using a particulate diverter is detailed in this paper, showcasing its application in both producer and injector wells. The learning curve associated with the particulate diverter has paved the way for optimizing hydraulic fracturing dynamics, allowing for the execution of up to three pumping stages in a single pumping operation.\u0000 This paper outlines the workflow developed for the application of particulate diverter technology in multiple wells in the Llanos basin; the success of this implementation is attributed to a comprehensive learning curve that involved various stages, including diagnosis, design, simulations, laboratory tests, execution, and post-work results.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"172 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527575","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":"Breaker Placement in Sand Control Lower Completions – New Challenges and Potential Solutions","authors":"M. Byrne, L. Djayapertapa, K. Watson","doi":"10.2118/217914-ms","DOIUrl":"https://doi.org/10.2118/217914-ms","url":null,"abstract":"\u0000 Production and injection wells for oil and gas and carbon storage reservoirs often require sand control across the reservoir section to enable fluids to flow and to prevent larger formation solids from moving. In many of these wells, chemical breaker treatments are pumped prior to production or injection to help to reduce any drilling or completion induced formation or completion damage. Delivering these breakers to the target such as residual drilling mud cake can be challenging and rules of thumb have often been used to guide this process. More rigorous methods to optimise breaker placement and design are now available.\u0000 CFD (Computational Fluid Dynamics) enables fluid flow in complex geometries to be modelled and predicted. Breaker placement during the well completion process involves the complex geometry of the well, the lower completion and the reservoir and fluid flow or displacement. The full geometry of vertical or horizontal wells, with induced fractures, multiple wellbores, perforations or mini-bores should and can be captured using CFD. Breaker pumping whether bull-headed, through a wash pipe, coiled tubing or more sophisticated rotating and jetting needs to be simulated in order to determine its efficiency.\u0000 Numerous simulations for different well types, completions and breaker deployment methods have revealed that even with the best intentions and rules of thumb, it can be challenging to place breaker to the target and for breaker concentrations required for efficient dissolution of residual damage to be maintained. In particular gravel packed completions present challenges. Fluids will always take the path of least resistance and in gravel packed completions this is often back up the well between the wash pipe and the screens missing the intended target. The additional resistance of the gravel in the annulus tends to prevent efficient breaker penetration to mud cake or perforations beyond. If the breaker does penetrate, then coverage of the damaged zone can be patchy and early losses can result. Simulations have also identified potential mitigations such as alternative deployment rates, displacement fluids prior to breakers and duration of breaker placement. The benefits of targeted breaker placement during pump and pull or jetting operations has also been evaluated.\u0000 Challenges in placing breaker effectively in sand controlled wells are addressed using complex numerical modelling. Replicating well geometry and all fluid flow paths are essential in order to optimise breaker placement and reduce residual formation and completion damage. The methods and examples shared will enable more effective clean-up of oil, gas, water, hydrogen and CO2 wells.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"182 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527572","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 Recovery Through Innovative Formation Damage Treatment","authors":"E. Moen, R. Antonsen, E. A. Ejofodomi","doi":"10.2118/217866-ms","DOIUrl":"https://doi.org/10.2118/217866-ms","url":null,"abstract":"\u0000 Formation damage can be a major challenge in maintaining the productivity and profitability of aging oil and gas wells. Traditional solutions, such as bullheading chemical treatments from the surface, often provide only a temporary boost in production and fail to address the root cause of the formation damage. The lack of sustainable and reliable outcome from such methods, have played a critical role in the search for an alternate approach that can effectively address the presence of formation damage and sustainably boost the production recovery in existing producing wells,\u0000 This paper presents an innovative approach to overcome the adverse effects of formation damage and achieve sustained well production recovery. It is a data-driven process that integrates a downhole, hydraulically activated system to restore and sustain productivity of sub-par producing wells. The process involves selecting the proper well candidates, identifying the existing damage mechanism causing poor production, and designing the optimum treatment operationally deployed via a downhole, hydraulically activated system, specifically configured to match the wellbore condition and design requirements. This focused treatment delivery ensures sustained production uplift and increased operational reliability. Several field case studies are presented that demonstrates the effectiveness of this approach in eliminating formation damage and achieving sustained production recovery in existing wellbores.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"75 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527709","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 Comprehensive Review of Techniques Enabling OHGP Completions in Low Frac Window Environment","authors":"M. Beldongar, B. Gadiyar, J. Jeanpert, A. Yeneapre, M. Bouguetta","doi":"10.2118/217851-ms","DOIUrl":"https://doi.org/10.2118/217851-ms","url":null,"abstract":"\u0000 Openhole gravel packing has proven to be one of the best sand control completion methods in the industry with high reliability and low skin. As more and more wells are being drilled in challenging environment (long drain lengths, depleted formation, wellbore stability concerns, presence of faults, etc.) with low fracture window, the ability to fully pack the openhole sections constrains the wider use of the method. Many techniques have been used to overcome the low fracture window challenge both in alpha beta and shunted gravel packing. This paper will review the techniques used in both gravel packing approaches, highlight their working mechanisms, and provide a comparison of these methods.\u0000 Techniques such as packing with friction reducer, BOP open, use of lighter carrier fluids, running diverter valves, wash-pipe less Bottom Hole Assembly (BHA), managed pressure gravel packing etc. have been successfully used depending on the available fracture margin, well configuration and gravel packing technique. The paper will briefly touch on the challenges leading to low fracture margin and the necessity to utilize one or a combination of the techniques to fully pack wells. It will then describe the working principle of each of the techniques, provide the advantages and disadvantages of the techniques. This will be complemented with several case histories showing how these wells were successfully completed despite the low fracture pressure window.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"158 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527577","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":"Reservoir Sandstone Wettability in Relation to Injection Water Salinity and Reservoir Temperature","authors":"Dhrubajyoti Neog, A. S. Rahman, P. Borgohain","doi":"10.2118/217899-ms","DOIUrl":"https://doi.org/10.2118/217899-ms","url":null,"abstract":"\u0000 The efficacy of low-salinity water flooding is attributed to various factors, including rock mineralogy, reservoir fluid composition, and the temperature and salinity of liquid-liquid and liquid-solid interactions. The objective of the proposed study is to examine the influence of injection water salinity on reservoir rock wettability as well as the functions fulfilled by monovalent and divalent cations derived from salt solutions in the water flooding procedure. The present study employs the sessile drop method to measure contact angle, enabling crude oil-reservoir rock interaction at varying formation water salinities. Contact angle measurements were taken at two temperatures representative of the reservoir temperatures of two wells in the upper Assam basin, India. The initial phase of the experiment involved the characterization of the porous medium responsible for crude oil production as well as the reservoir fluids. Subsequently, synthetic salt solutions with varying salinities were prepared. The alteration in wettability was then analyzed in relation to the salinity levels of the injected water at two distinct reservoir temperatures, namely 80°C and 100°C. The study was conducted in reference to an oil-saturated core located in the upper Assam basin. The results obtained were compared to draw conclusions regarding the effect of temperature and salinity on the wettability of reservoir rock. The results of the sessile drop method were further analyzed using the pendant drop method, with interfacial tension (IFT) estimation for liquid-liquid interaction.\u0000 The experimental study conducted on oil-saturated cores has yielded significant findings. It has been observed that, at a temperature of 80 °C and a salinity range of 500–7000 ppm in a sodium chloride (NaCl) solution, the contact angle increases with an increase in salinity. However, this trend deviates at 100 °C for salinities of 5000 ppm and 7000 ppm NaCl solutions. Similarly, the wettability measurement with contact angle estimation for calcium chloride (CaCl2) solutions at a low reservoir temperature of 80 °C also displayed an increasing trend of increasing contact angle with an increase in salinity. However, this trend deviates when the salinity of CaCl2 salt solutions is increased beyond 3500 ppm at an increasing temperature of 100 °C. The findings demonstrate that salinity and the effect of temperature on wetting properties are significant. Further analysis with interfacial tension (IFT) estimation infers that both contact angle and IFT are reduced with increasing temperature for interactions between the liquid and solid phases, as well as between liquid phases. Based on the results, it can be concluded that the wettability of sandstone rocks varies with salinity and temperature. Higher water-wetting properties are obtained when the temperature of interaction is increased for low-salinity brine solutions, irrespective of whether monovalent or divalent cationic brine solutions are use","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"63 15","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527567","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":"Multiphase Flow Pattern and Screen Selection: Two Overlooked Parameters Essential to Reservoir Control Valve Optimization","authors":"C. A. Malbrel, R. Kale, J. Agarwal, K. Gohari","doi":"10.2118/217843-ms","DOIUrl":"https://doi.org/10.2118/217843-ms","url":null,"abstract":"\u0000 The deployment of sophisticated Autonomous Inflow Control Valves (AICV) to manage reservoir uncertainty and water production in stand-alone completion is becoming increasingly popular, and the range of options available is constantly evolving. To date, much of the extensive testing performed with AICVs has assumed homogenous/dispersed flow (taking no direct account of production phase separation) and has ignored the potential role of varying screen geometries. Under a wide range of downhole conditions, stratified flow may be a more likely scenario and the full scale testing of AICV assembly under realistic downhole field conditions provides insights into the annular flow behavior and identifies critical interactions between the AICV and the screen, potentially leading to new means of enhancing AICV performance.\u0000 A series of multiphase flow tests was performed on full size screen and housing assemblies to verify flow pattern under realistic conditions and assess the potential for screen geometry to have an impact on the AICV performance in stratified flow conditions.\u0000 Various features of the screens, such as screen type (mesh screen, wire wrap), and screen/basepipe standoff height were investigated under various water fractions, flow rates and oil viscosities. The screen jacket was also partially blocked by a sleeve to simulate the partial burial of the screen in the wellbore. The multiphase flow patterns in the annular space around the screen and inside the valve housing were monitored through observation windows and high-speed camera, in conjunction with pressure drop across the screen and the entire assembly.\u0000 Under normal flowrates, it is observed that the multiphase flow shows a stratified flow pattern around the screen, with the location of the water/oil interface highly sensitive to the oil viscosity. For high viscosity oil (100cp), the W/O interface is very low, resulting in a high water phase velocity high. This provides another reason why the onset of water production in heavy oil is often causing rapid screen plugging and high drawdown. Under these conditions, stratified flow is also prevalent in the valve housing, irrespective of the screen type.\u0000 Under semi buried conditions, the screen type and standoff between the screen jacket and the basepipe played an outsize role in defining the flow pattern inside the housing. With a mesh screen and tall standoff, the flow pattern remains largely stratified while a wire wrap screen yields a bubbly/misty condition. As a result of these change in flow pattern, AICV performance is expected to be degraded when wire wrap screens are used in partially collapsed wellbore.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"140 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527579","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":"Analyzing Gas Well Productivity Change with Production in Unconsolidated Sandstone Using Rate Transient Analysis","authors":"Anand Kumar, Pratik Marandi, Deepak Verma","doi":"10.2118/217863-ms","DOIUrl":"https://doi.org/10.2118/217863-ms","url":null,"abstract":"\u0000 The primary objective of this paper is to demonstrate the changing productivity of the cased hole gravel packed gas wells due to wellbore matrix disturbance, rapid bean up operations and how daily production data (rates and flowing pressures/ temperature) can be used to analyse gas well performance along with estimation of Gas In Place. This work includes the identification of well problems and productivity changes, attributed to wellbore matrix disturbance or sub-surface issues in unconsolidated sands.\u0000 The analysis method used in this work is Rate Transient Analysis along with Pressure Transient Analysis. Bottom hole temperature behavior and Decline Curve analysis are also analyzed to validate the results captured from RTA. RTA is ideal for establishing a well's productive capability early in its life (after 3-6 months) and categorizing subsequent well decline behavior as either reservoir depletion or productivity loss through time (or a combination of the two). Through interpretation of diagnostic plots, such as the Flowing Material Balance Analysis and Type Curve Analysis plots, specific productivity issues can be easily identified and classified using simple pattern recognition.\u0000 Field examples from multiple gas wells across KG Offshore Deep Water (Water depth > 400m), completed with cased hole gravel pack, are included in our study. The present case study indicate the apt use of RTA, PTA and other bottom hole parameters to determine current K, changing skin & the most important GIIP of single well gas fields. RTA will supplement and to some extent give the actual estimation with less error. Deliverability issues such as wellbore matrix disturbance and gravel pack degradation associated with unconsolidated sands are identified. The issues has been validated by flowing temperature behavior. Results show how RTA can be used as a practical screening tool, identifying underperforming wells and quantifying the potential benefits of remedial action based on remaining reserves.\u0000 This paper presents a novel application for RTA - as a screening tool for diagnosing underperforming wells and estimating their optimum producing rates. The industry tends to undervalue the potential benefit of all but the simplest remedial measures for underperforming producing wells for two reasons- 1. Poor performance is often simply accepted as a statistical reality and 2- operators do not even realize that their wells are underperforming. In case of deep water, work over job or drilling new well is a very costly affair. Also, time plays a major role in economics of a development project. If the issue(s) can be resolved, production improvements aggregated field-wide could have tremendous economic implications.","PeriodicalId":518880,"journal":{"name":"Day 2 Thu, February 22, 2024","volume":"178 7","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140527574","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}