SPE Production & Operations最新文献

{"title":"Artificial Neural Network Model to Predict Production Rate of Electrical Submersible Pump Wells","authors":"A. Sabaa, M. Abu El Ela, Ahmed H. El-Banbi, M. Sayyouh","doi":"10.2118/212284-pa","DOIUrl":"https://doi.org/10.2118/212284-pa","url":null,"abstract":"\u0000 Production data are essential for designing and operating electrical submersible pump (ESP) systems. This study aims to develop artificial neural network (ANN) models to predict flow rates of ESP artificially lifted wells. The ANN models were developed using 31,652 data points randomly split into 80% (25,744 data points) for training and 20% (5,625 data points) for testing. Each data set included measurements for wellhead parameters, fluid properties, ESP downhole sensor measurements, and variable speed drive (VSD) sensors parameters. The models consisted of four separate neural networks to predict oil, water, gas, and liquid flow rates. Sensitivity analyses were performed to determine the optimum number of input parameters that can be used in the model. The best performance was achieved with ANN models of 16 input parameters that are readily available in ESP wells.\u0000 The results of the best ANN configuration indicate that the mean absolute percent error (MAPE) between the predicted flow rates and the actual measurements for the testing data points of the oil, water, gas, and liquid networks is 3.7, 5.2, 6.4, and 4.1%, respectively. In addition, the correlation coefficients (R2) are 0.991, 0.992, 0.983, and 0.979 for the estimated oil, water, gas, and liquid flow rates for the testing data points, respectively. The performance of the ANN models was compared against performance of published physics-based models and the results were comparable. Unlike the physics-based methods, the ANN models have the advantage that they do not require periodic calibration. The ANN models were used to predict the flow rate curves of an oilwell in the Western Desert of Egypt. The results were compared to the actual separator test data. It was clear that the model results matched the actual test data.\u0000 The ANN model is useful for predicting individual well production rates within wide variety of pumping conditions and completion configurations. This should allow for continuous monitoring, optimization, and performance analysis of ESP wells as well as quicker response to operational issues. In comparison to traditional separators and multiphase flowmeters (MPFMs), the use of the developed ANN models is simple, quick, and inexpensive.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"237 1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121093301","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":"Surgical Coiled Tubing Stimulations: Step Changes in Effectiveness, Efficiency, and Characterization of Waterflooding Interventions","authors":"S. Hassig Fonseca, P. Ramondenc, Adolfo Sandoval, Cabe Vreeland, Rommy Cevallos, C. Villacres, D. Flor, Diego Quinatoa, Santiago Yepez, A. Azancot, Yennifer Lopez, Rosario Fraga, J. L. Freire, C. Giol, Wei Zhou","doi":"10.2118/209028-pa","DOIUrl":"https://doi.org/10.2118/209028-pa","url":null,"abstract":"\u0000 An innovative coiled tubing (CT) real-time flow measurement tool was introduced in Ecuador to reformulate the stimulation workflow in water injectors, which comprised evaluation and treatment. This new technology enabled an integrated, single-run workflow instead—initial injectivity measurements, diagnostics, treatment, post-stimulation injectivity measurements, and final diagnostics. This novel, rigless approach reduced equipment footprint, operational time, and cost, and it improved production as compared with the conventional approach, despite accrued capital discipline constraints.\u0000 Conventionally, operators rely on workover rigs and multiple product lines to diagnose, stimulate, and evaluate injector wells. Several challenges and inefficiencies were addressed by deploying the CT real-time flow measurement tool. Each intervention was designed to be completed with a single CT run and without the need for a workover rig, thus saving cost and time. Tailored diversion methods substituted the need for drillpipe to set mechanical packers. Prestimulation injection logging test (ILT) results obtained with that innovative tool, coupled with real-time control of depth and high-pressure jetting during execution, enabled effective placement of the stimulation treatment. Ultimately, post-treatment ILTs confirmed treatment effectiveness and final wellbore downhole conditions.\u0000 Introduction of the CT real-time downhole flow measurement tool allowed operational objectives to be met in a single run, without additional interventions, with or without a workover rig on site. When workover rigs were present, this improved workflow saved an average of 15% operational time. In cases without a workover rig, 105 hours of rig time were saved (without considering rig mobilization time).\u0000 Four case studies are presented. The first two cases demonstrate how acquisition of ILTs throughout the intervention enabled optimization of fluid placement and introduction of diverter methods. The third case covers a scenario where there was an initially low injectivity and highlights the challenges and lessons associated with recovering injectivity. The fourth case presents challenges unique to flowmeter measurements in heavy-oil environments. In each case, effectiveness of the optimized treatment was measured by two metrics: improvements in net injectivity and uniformity of injection profile, both of which drive the effectiveness of secondary recovery in connected producer wells. On average, wells intervened with this approach featured an improvement in injectivity of 301% (compared with 226% conventionally) and in their injection profile homogeneity by 13%. As a result, the productivity in connected wells improved by as much as 74% and an average of 39% (compared with 14% conventionally).\u0000 This innovative workflow is a step change over conventional approaches to rejuvenate waterflooding. It combines the capabilities of delivering treatments via CT and the power of real-time down","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126617557","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 the Benefits of Designing a Multifunctional Surfactant Blend From Laboratory Scale to Field Scale in Hydraulic Fracturing under High-Salinity Conditions: A Case Study of the Mississippian Limestone Play","authors":"Xiao Jin, Alhad Phatak, Dawn M. Friesen, A. Sanders, Ginger Ren, Nicholas A. Koster","doi":"10.2118/210066-pa","DOIUrl":"https://doi.org/10.2118/210066-pa","url":null,"abstract":"\u0000 Surfactants are typically used in hydraulic fracturing applications to perform a single function, which results in multiple surfactants being used during operations. In this study, flow loop and coreflood tests were conducted with slickwater fracturing fluid systems and analyzed in conjunction to observe the effectiveness of flowback surfactants and their ability to increase friction reducer performance. A multifunctional surfactant blend (MSB) is tested against surfactant formulations commonly used either as a flowback aid or as a performance enhancer for low-cost friction reducers in harsh conditions. A case study is conducted using wells in the Mississippian limestone play to correlate laboratory investigations to field observations.\u0000 Each surfactant solution was tested with a friction-reducing polymer in synthetic brine containing a salt concentration of 200 000 mg/L representative of harsh field conditions in the laboratory evaluation. Coreflood tests were conducted under reservoir conditions to evaluate flowback efficiency quantified by regained permeability. To test the ability of the surfactants to improve friction reduction (FR) performance, a 0.4-in. inner diameter friction flow loop was used. In the field-scale application, four wells were hydraulically fractured with two wells acting as control cases and two wells including the addition of the MSB. Completions and production data are presented to compare the performances of the wells and the efficacy of the MSB at the field scale.\u0000 Friction flow loop testing showed that slickwater fluids with commonly used flowback surfactant formulations, including the MSB, can greatly improve the performance of economical freshwater friction reducers, even in a high calcium (13 000 mg/L) synthetic brine. The same slickwater/surfactant fluids used in the flow loop tests were evaluated in coreflood tests. Depending on the degree of polymer-induced damage created in the core samples, fluids containing the MSB offered the most consistent regained permeability. The laboratory-scale study shows that the MSB is functional for both polymer damage mitigation and acts as a performance booster for the FR, allowing a more economical friction reducer to be selected for slickwater fracturing. In field applications, including the MSB in the fracturing fluid resulted in increased oil production volumes and/or a reduced need for remedial operations throughout the early life of the well.\u0000 The results of this study show that by properly utilizing the friction flow loop and coreflood laboratory-scale experiments, an optimized MSB can be selected for hydraulic fracturing operations at the field scale. By selecting a flowback surfactant formulation that also increases friction reducer performance, a lower friction reducer dosage or a more economical friction reducer can potentially lead to operational savings at the field scale.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129375759","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":"Experimental Investigation of the Effects of Fluid Viscosity on Electrical Submersible Pumps Performance","authors":"W. Monte Verde, E. Kindermann, J. L. Biazussi, V. Estevam, B. P. Foresti, A. Bannwart","doi":"10.2118/210603-pa","DOIUrl":"https://doi.org/10.2118/210603-pa","url":null,"abstract":"\u0000 Electrical submersible pumps (ESPs) are an important artificial lift method used in oil production. ESPs can provide high production flow rate, are flexible, and can be installed in highly deviated wells, subsea deepwater wells, or on the seabed. ESP performance is generally characterized by manufacturers using only water as fluid. However, oil properties are very different from water and significantly alter the pump’s performance. Operating ESPs with viscous fluids leads to degraded pump performance. Therefore, knowing the ESP’s performance when pumping viscous fluid is essential to properly design the production system. In this work, we present an experimental study of ESP performance operating with viscous flow. A total of six ESP models were tested, operating at four different rotational speeds and 11 viscosities, resulting in a comprehensive database of more than 5,800 operating conditions. This database contributes to the literature given the lack of available data. We also perform a phenomenological analysis on the influence of operational parameters, such as viscosity, rotational speed, specific speed, and rotational Reynolds number. The database and analyses performed are central for future models predicting the viscous performance of ESPs. The results from our investigation and tests showed that the increase in viscosity causes (1) a reduction in the head and (2) an increase in drive power, resulting in (3) a sharp decrease in efficiency. However, increasing rotational speed tends to mitigate this performance degradation. Efficiency and flow rate correction factors are virtually independent of the flow rate within the recommended operating region. This is not true for the head correction factor, which is not constant. The pump geometry seems to influence its performance as ESPs with higher specific speed are less impaired by viscous effects. The database obtained in the present work is available in the data repository of the University of Campinas, at the address presented by Monte Verde et al. (2022).","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126152751","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":"Well Production Optimization under the Scale Effect and CO2-WAG Injection in a Carbonate Model of the Brazilian Pre-Salt","authors":"Luiz Carlos Gomes Filho, M. A. Sampaio","doi":"10.2118/212269-pa","DOIUrl":"https://doi.org/10.2118/212269-pa","url":null,"abstract":"\u0000 Scale represents a risk to the profitability of projects in the oil exploration and production industry. The occurrence of the phenomenon has the potential to cause severe damage to producer and injector wells, subsea lines, and surface systems, commonly requiring the cleaning and replacement of these elements and resulting in lost profit because of reduced production efficiency, need for unscheduled maintenance stoppages, and, in the most serious cases, permanent losses of wells, lines, and equipment. The problem becomes even more severe in projects that use the injection of reactive fluids into the reservoir, as is the case with carbon dioxide-water alternating gas (CO2-WAG) injection. To avoid such an occurrence, scale inhibitors are used, which are continuously dosed at various points in the production flow, from subsea chemical injection mandrel, commonly positioned at the ends of the production columns, wet Christmas tree valves, and at various positions in the plant process on the surface. However, the regions upstream of the chemical injection mandrels, such as the perforations zone and the reservoir itself, are normally not protected by continuous-dosing inhibitors and are therefore critical for the occurrence of the phenomenon. These critical points require removal operations when the accumulation of scale is significant to economically justify a treatment. To prevent the recurrence of scale in the short term, the cleaning operation is commonly associated with the squeeze of inhibitors into the porous medium. The effect of this inhibition, however, is temporary, as the inhibitor adhered to the rock is released with the water production, until it ceases to be effective after a determined accumulated production of this fluid, requiring the evaluation of a new application of the product. This work proposes a workflow for optimizing cleaning treatments associated with scale inhibitor injection, as well as CO2-WAG fluid exchanges, aimed at protecting the reservoir and well producer perforations, and seeking to optimize the project’s net present value (NPV) in operations carried out by means of rigs or remotely by the stationary production unit (SPU). To this end, a study was carried out by coupling producer scale and inhibition proxies to a flow simulation with a reactive transport model, representative of some fields of the Brazilian pre-salt. The method developed, in addition to providing greater robustness to the predicted production curve by considering the occurrence of scale in the producer perforations, can identify optimal time windows for the treatment, even if they are in periods where the inhibition is no longer effective. The results obtained in the study for a single producing well indicate a substantial gain in the NPV with the use of the proposed methodology, around 13 million USD in relation to the proposal of treatments always carried out in a preventive way. The application also indicated that it is more advantageous to c","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126326692","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":"Produced Water Treatment: Review of Technological Advancement in Hydrocarbon Recovery Processes, Well Stimulation, and Permanent Disposal Wells","authors":"S. Eyitayo, M. Watson, O. Kolawole, P. Xu, R. Bruant, L. Henthorne","doi":"10.2118/212275-pa","DOIUrl":"https://doi.org/10.2118/212275-pa","url":null,"abstract":"\u0000 Produced water (PW) is the most significant waste product in oil and gas exploitation, and numerous challenges are associated with its treatment. For over half a century, PW treatment and handling have evolved from a waste product to a reusable stream for the petroleum industry. PW is reused and recycled for hydrocarbon recovery processes, well completion, stimulation, drilling, etc. Despite this usage, enormous volumes are still required to be disposed of in the subsurface aquifers or surface water bodies after treatment. Challenges to PW treatment are related mainly to widely varying PW characteristics, nonuniformity of water treatment systems for different fields, and difficulty in designing novel technology due to changing production rates and other design parameters. This paper focuses on purpose-specific water treatment units used in various activities within the oil and gas industries and technological advancement. A detailed account of the historical development of current water treatment practices, disposal, available technology, and challenges in implementation are presented. Forward-looking recommendations are given on how emerging technologies can be integrated into everyday oil and gas activities to achieve the purpose-specific treatment goal.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128992711","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 Water Softening in Heavy Oil Steamflood Operations","authors":"Prakhar Prakash, Reid Concienne, T. Demayo, Kirsten Towne","doi":"10.2118/206115-pa","DOIUrl":"https://doi.org/10.2118/206115-pa","url":null,"abstract":"\u0000 Pigging of once through steam generators (OTSGs) has indicated various types of scales, the most predominant of these being silicates of hardness causing ions. It was noted that scaling propensity can potentially go up with higher steam quality (SQ) as the reject stream gets concentrated with ions. However, models suggested that there are benefits of higher SQ in enhancing fuel savings (8%) and electricity savings (2%) when SQ was increased by 20%. The challenges of higher SQ were noted in terms of increased scaling tendency and therefore the need for improved softening. In Field D, the service cycle, the backwash cycle, and the brining cycle were optimized leading to a gain in throughput and reduction in salt consumption. Service cycle improvement gained 30 to 130% in throughput between two regenerations, backwash cycle improvement by fluidizing the bed to nearly 35% helped gain 10% in throughput, and reduction of brining cycle from 75 to 48 minutes helped reduce salt consumption by 56% without impacting the throughput. In Field B, a 6-month pilot revealed that shallow shell resins where ion exchange is more efficient due to inert core (better intraparticle diffusion control) can enhance the throughput by 30 to 80% and simultaneously reduce the number of regenerations by 15 to 30%. Resin fouling is still a major challenge to contend with as oil can foul the resin and throughput can decline by 0.5 to 3 folds. In a plant operation, where there are multiple softener and brine vessels, there is a need to optimize them as a system. Reliability, availability, and maintainability (RAM) models are used in Field C to (a) address equipment configuration optimization with impact on capital capacity expansion project scope, (b) understand how net soft water delivery capacity was affected by increases in inlet hardness, and (c) assess through a comparison scenario if the large cost of addressing the valve issue in an upstream nutshell filter was worth the lost production opportunity related to unplanned downtime.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"82 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115173596","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":"Effects of Altering Perforation Configurations on Proppant Transport and Distribution in Freshwater Fluid","authors":"Shabeeb Alajmei, J. Miskimins","doi":"10.2118/210573-pa","DOIUrl":"https://doi.org/10.2118/210573-pa","url":null,"abstract":"\u0000 Proppant transport in horizontal wellbores has received significant industry focus over the past decade. One of the most challenging tasks in the hydraulic fracturing of a horizontal well is to predict the proppant concentration that enters each perforation cluster within the same stage. The main objective of this research is to investigate the effect of different perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. To simulate a fracturing stage in a horizontal wellbore, a laboratory-based 30-ft horizontal clear apparatus with three perforation clusters is used. Fresh water (~1 cp) is used as the carrier fluid to transport the proppant. This research incorporates the effect of testing three different injection rates each at four different proppant concentrations on proppant transport. Different perforation configurations are also used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations for the tested 100-mesh proppant. The proppant is mixed with fresh water in a 200-gallon tank for at least 10 minutes to ensure the consistency of the slurry mixture. The mixture is then injected into the transparent horizontal wellbore through a slurry pump. This laboratory apparatus also includes a variable frequency drive, a flowmeter, and two pressure transducers located right before the first two perforation clusters. Sieve analysis is conducted to understand the ability of fresh water to carry bigger particles of the mixture at different injection rates, proppant concentrations, and perforation configurations.\u0000 The results show different fluid and proppant distributions occur when altering the perforation configurations, injection rates, and proppant concentrations. The effect of gravity is extreme when using a limited-entry configuration at each cluster [1 shots/ft (SPF)] located at the bottom of the pipe, especially at low injection rates, resulting in uneven proppant distribution with a heal-biased distribution. However, even proppant distribution is observed by changing the limited entry perforation configuration to the top of the horizontal pipe at similar injection rates and low proppant concentration. Increasing the proppant concentration reduces the void spaces between the particles and pushes them away toward the toe cluster. Even proppant distribution is also observed across the three perforation clusters when using higher flow rates and a 2 SPF perforation configuration located at both the top and the bottom of the pipe. The results show uneven fluid and proppant distributions between clusters with a toe-biased distribution when altering the perforation configurations to 3 and 4 SPF.\u0000 The results of the sieve analyses show different size distributions of the settled and exited proppant through different perforations and clusters. This illustrates the ability of fresh water to transport different","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114306264","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":"Physical Testing of a High-Speed Helicoaxial Pump for High Gas Volume Fraction Operation","authors":"C. Ejim, Jinjiang Xiao, Wee Sun Lee, Wilson Zabala","doi":"10.2118/210584-pa","DOIUrl":"https://doi.org/10.2118/210584-pa","url":null,"abstract":"\u0000 High-speed-rotor dynamic pump operation for downhole or surface production is required and also beneficial to handle very high gas volume fraction (GVF) flows. Operating speeds of these pumps can be in excess of twice those of conventional pumps. This study presents results showing that a high-speed helicoaxial pump (HAP) can operate satisfactorily at intake GVFs of up to 98%. The findings increase capabilities of field engineers and operators to boost and maximize production from high gas content wells.\u0000 The HAPs tested had a 4-in. housing outer diameter (OD) and shaft rotational speed of 6,000 revolutions per minute (RPM). HAP rotor and diffuser clearances were 0.010 and 0.020 in. A water sprayer was included at the HAP inlet. Water volume flow rates were held constant and that for air was varied. Water volume flow rate range was 63 to 143 B/D, and 549 to 3,238 B/D for air. Intake pressures varied from 14 to 76 psig, and average temperature across the HAPs was 20°C. The corresponding measurements were recorded during observed stable pump operation for each test point.\u0000 The results showed that the HAPs had stable operation during the tests for intake GVF range from 79 to 98%. The range of dimensionless pressure boost (DPB) was between 0.0184 and 0.0501, indicating that at such high speeds, the HAPs were able to add energy to the fluid even at high intake GVFs. For a given intake gas/liquid density ratio, the DPB decreased with increasing intake GVF. For the same liquid flow coefficient and intake GVF, increasing the intake gas/liquid density ratio increased the DPB of the HAP. The higher intake density ratio enhanced the HAP’s capability to provide positive pressure boost up to an intake GVF just above 98%. It was also observed that the HAP with the tighter diffuser-rotor clearance of 0.010 in. had a higher pressure boosting capability than the HAP with 0.020-in. diffuser-rotor clearance. Proper pump intake flow conditioning and homogenization using the water spray facilitated stable operation of the HAPs. Overall and in conclusion, running HAPs at high speeds in addition to optimizing certain features of the HAPs can result in stable pump operation and enhanced pressure boosting in high GVF flows.\u0000 This study mainly highlights the importance of operating HAPs at high speeds of up to 6,000 RPM. Tightening clearances between rotordynamic components and tailored inlet flow conditioning are also additional features that enhance pressure boosting. This architecture opens up opportunities for field operators and engineering personnel to maximize hydrocarbon production from their very high gas content field assets, thereby increasing the economic bottom line for the stakeholders.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129580316","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":"Online Monitoring of Inner Deposits in Crude Oil Pipelines","authors":"R. Giro, G. Bernasconi, G. Giunta, Simone Cesari","doi":"10.2118/209825-pa","DOIUrl":"https://doi.org/10.2118/209825-pa","url":null,"abstract":"\u0000 The formation of deposits is a very common issue in oil and gas pipeline transportation systems. Such sediments, mainly wax and paraffine for crude oil, or hydrates and water for gas, progressively reduce the free cross-sectional area of the pipe, leading in some cases to the complete occlusion of the conduit. The overall result is a decrease in the transportation performance, with negative economic, environmental, and safety consequences. To prevent this issue, the amount of inner deposits must be continuously and accurately monitored, such that the corresponding cleaning procedures can be performed when necessary. Currently, the former operation is still dictated by best-practice rules pertaining to preventive or reactive approaches, yet the demand from the industry is for predictive solutions that can be deployed online for real-time monitoring applications. The paper moves toward this direction by presenting a machine learning methodology that leverages pressure measurements to perform online monitoring of the inner deposits in crude oil trunklines. The key point is that the attenuation of pressure transients within the fluid is dependent on the free cross-sectional area of the pipe. Pressure signals, collected from two or more distinct locations along a pipeline, can therefore be exploited to estimate and track in real time the presence and thickness of the deposits. Several statistical indicators, derived from the attenuation of such pressure transients between adjacent acquisition points, are fed to a data-driven regression algorithm that automatically outputs a numeric indicator representing the amount of inner pipe debris. The procedure is applied to the pressure measurements collected for one and a half years on discrete points at a relative distance of 40 and 60 km along an oil pipeline in Italy (100 km length, 16-in. inner diameter pipes). The availability of historical data prepipe and postpipe cleaning campaigns further enriches the proposed data-driven approach. Experimental results demonstrate that the proposed predictive monitoring strategy is capable of tracking the conditions of the entire conduit and of individual pipeline sections, thus determining which portion of the line is subject to the highest occlusion levels. In addition, our methodology allows for real-time acquisition and processing of data, thus enabling the opportunity for online monitoring. Prediction accuracy is assessed by evaluating the typical metrics used in the statistical analysis of regression problems.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"22 6S 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133132569","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}