Spe Production & Operations最新文献

{"title":"An Interim Report on Predicting Pressure Rise due to the Thermal Expansion of Trapped Liquids in Subsea Oil and Gas Equipment","authors":"Ramechecandane Somassoundirame, Eswari Nithiyananthan","doi":"10.2118/204473-pa","DOIUrl":"https://doi.org/10.2118/204473-pa","url":null,"abstract":"\u0000 The objective of the present work is to propose a methodology to predict pressure rise due to the thermal expansion of trapped liquids using computational fluid dynamics (CFD). The present study also provides a comparison between the various methods used for pressure buildup calculations that are widely used in oil and gas industries. A comparison of standard thermodynamic calculations with transient 3D CFD analysis reveals that transient CFD analyses can provide deeper insights on the temperature and velocity fields in trapped volumes. The application of the proposed method is not just restricted to a single component/equipment in the subsea field but can be applied to any trapped volume in subsea equipment. In the present study, the pressure buildup in a downhole (DH) port of a subsea Christmas tree (XT) is presented for demonstration purposes; the same methodology can be extended to other equipment or regions of interest. Because of a lack of literature on the topic of pressure rise due to thermal expansion of trapped fluids, engineers are forced to make several assumptions without knowing the effect of each term or parameter on the final pressure calculated. In this study, the percentage change/variation of the final pressure using the various forms of a standard analytical pressure rise equation is also discussed in detail.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47761809","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Mathematical Model for Predicting Long-Term Productivity of Channel-Fractured Shale Gas/Oil Wells","authors":"Xu Yang, B. Guo, T. A. Timiyan","doi":"10.2118/204471-pa","DOIUrl":"https://doi.org/10.2118/204471-pa","url":null,"abstract":"\u0000 This study focuses on the development of an analytical model to predict the long-term productivity of channel-fractured shale gas/oil wells. The accuracy was verified by comparing productivity calculated by the proposed model with numerical results. Sensitivity analysis was conducted to analyze significant parameters on the performance of channel fracturing. Field application of the model was conducted using production data obtained from an Eagle Ford Formation dry gas well, which was completed using channel fracturing. The procedure for estimating reservoir and stimulation parameters from production data was provided. The results indicated that the equivalent fracture width obtained from our model is consistent with the inversion of cubic law. Comparison with numerical simulations demonstrated that the proposed model might under- or overestimate well productivity, with mean absolute percentage error (MAPE) values of less than 8%. Sensitivity analysis indicated that, with the increase of fracture width, fracture half-length, and matrix permeability, the productivity of channel-fractured wells increases disproportionately. In addition, well productivity will increase as the ratio of the pillar radius to the length of channel fracture decreases, provided that the proppant pillars are stable and the fracture width is held constant. Under the conditions of smaller fracture width and larger matrix permeability, the effect of using channel fracturing to increase well productivity is more significant. However, as the fracture width becomes large, the benefits of channel fracturing will diminish. The case study indicated that the shale gas productivity estimated by the proposed model matches well with field data, with MAPE and R2 of 12.90% and 0.93, respectively. The proposed model provides a basis for optimizing the design of channel fracturing.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47565487","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Comprehensive Fall Velocity Study on Continuous Flow Plungers","authors":"O. Sayman, E. Pereyra, C. Sarica","doi":"10.2118/201139-ms","DOIUrl":"https://doi.org/10.2118/201139-ms","url":null,"abstract":"\u0000 The objective of this study is the experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. The dimensionless analysis conducted included the wall effect, inclination, and the liquid holdup correction of the fall stage. A fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers.\u0000 In a static facility, four sleeves with different height, weight, and outer diameter (OD); three balls made with different materials; and a bypass plunger are tested in four different mediums. The wall effect on the settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column, and the liquid holdup effect on the drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in the field scale.\u0000 Reference drag coefficient values of plungers are obtained for respective Reynolds number values. Experimental wall effect, liquid holdup, and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at the wellhead had two opposing effects; namely, reduced gas density, thereby reducing the drag and gas expansion that increased the gas velocity, which in turn increased the drag.\u0000 Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection, and the gas injection rate for plunger-assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using the drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections, and incorporating multiphase flow simulation.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-11-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201139-ms","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44316411","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Large-Scale Experiments on Slug-Length Evolution in Long Pipes","authors":"J. Kjølaas, T. E. Unander, M. Wolden, Heiner Schümann, P. R. Leinan, I. E. Smith, A. Shmueli","doi":"10.2118/203827-PA","DOIUrl":"https://doi.org/10.2118/203827-PA","url":null,"abstract":"\u0000 We present a unique set of two- and three-phase slug-flow experiments conducted in a 766-m-long, 8-in. pipe at 45-bara pressure, using Exxsol™ D60 fluid (ExxonMobil Chemical, Houston, Texas, USA) as the oil phase and nitrogen as the gas phase. The first one-half of the pipe was horizontal, while the second one-half was inclined by 0.5°. A total of 10 narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug-length development.\u0000 The results show that the mean slug length initially increases with the distance from the inlet, but this increase slows down, and the mean slug length typically reaches a value between 20 and 50 diameters at the outlet. At low mixture velocities (<3 m/s), the slug-length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were more than 250 pipe diameters (50 m). At higher mixture velocities (>3 m/s), the slug-length distributions are in general narrower. The effect of the water cut (WC) on the slug-length distribution is significant but complex, and it is difficult to establish any general trends regarding this relationship. Finally, it was observed that slug flow often requires a very long distance to develop. Specifically, in most of the slug-flow experiments, the flow regime 57 m downstream of the start of the horizontal section was not slug flow.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"895-909"},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46681087","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Pushing the Limits of Damage Identification Through the Combined Use of Coiled Tubing, Distributed Sensing, and Advanced Simulations: A Success Story from Japan","authors":"N. Yoshida, Satoshi Teshima, Ryo Yamada, Umut Aybar, P. Ramondenc","doi":"10.2118/194284-pa","DOIUrl":"https://doi.org/10.2118/194284-pa","url":null,"abstract":"\u0000 The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such an assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed-temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan.\u0000 The subject well experienced unexpected contamination of oil-based mud (OBM) and completion brine, which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging-tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions.\u0000 The following operational sequence was implemented: temperature-baseline measurements (6 hours), brine bullheading through the CT/tubing annulus at 0.2 bbl/min (22 hours), and shut-in (6 hours) for warmback. The long injection stage was required to ensure that enough fluid was being injected across the entire interval while keeping the downhole pressure at less than the fracturing pressure. Real-time DTS data during pumping and warmback indicated the presence of a main intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which might be a direct consequence of the low-injection-rate limitation. Post-job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against the DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results supported the presence of a larger intake in the middle interval and also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the larger-intake interval being the primary water-bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones.\u0000 This study demonstrates how integrated use of data from design to job execution to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water-production diagnostics in some extreme conditions when production-logging tools (PLTs) cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activi","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"1010-1025"},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/194284-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48308651","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimizing Fracturing Design and Well Spacing with Complex-Fracture and Reservoir Simulations: A Permian Basin Case Study","authors":"Hongjie Xiong, Songxia Liu, Feng Feng, Shuai Liu, Kaimin Yue","doi":"10.2118/194367-pa","DOIUrl":"https://doi.org/10.2118/194367-pa","url":null,"abstract":"\u0000 Proper lateral and vertical well spacing is critical to efficiently develop unconventional reservoirs. Much research has focused on lateral well spacing, but little on vertical spacing, which is important and challenging for stacked-bench plays such as the Permian Basin. Following the previous single-well study (Xiong et al. 2018), we performed a seven-well case study to optimize completion design and 3D well spacings, by integrating the latest complex-fracture-modeling and reservoir-simulation technologies. Those seven wells are located at the same section but also are vertically placed in four different zones in the Wolfcamp Formation in the southern Midland Basin.\u0000 With the latest modeling technologies, we first built a 3D geological and geomechanical model, and full wellbore fracture-propagation model for these seven wells, and then calibrated the model with multistage-fracturing pumping history of each well. The resulting model was then converted to an unstructured-grid-based reservoir-simulation model, which was then calibrated with production history. On the basis of the local geomechanical characterization, as well as confidence in the capacity of the models from our previous study, we conducted experiments in fracturing modeling to study the impact of different completion design parameters on fracture propagation, including cluster spacing, fracturing-fluid viscosity, pumping rate, and fluid and proppant intensities. With the statistical distributions of fracture length and height from different completion designs, we then optimized the completion design, and studied lateral and vertical well spacings.\u0000 The results show the following. The resulting fracture length and height from multistage fracturing treatments are in log-normal distribution, which provides great insights on the probability of well interference/fracture hits and drained/undrained reservoir volumes. Both fracture hits/well interference and drainage volume depend on the well spacings and corresponding well completion designs The hydraulic-fracture length, height, and network complexity mainly depend on in-situ stress, cluster spacing, cluster number per stage, and fluid and proppant intensity. For the Wolfcamp Formation in the southern Midland Basin, tighter cluster spacing with fewer perforation clusters per stage and high fluid and proppant intensity, might create larger fracture surface area, which will increase the initial production rate and the ultimate recovery.\u0000 Therefore, we can reasonably model complicated fracture propagation and well performance with the latest modeling technologies, and optimize both lateral and vertical well spacings, and the corresponding completion design. The application of those technologies could help operators save significant time and costs on well-completion and -spacing pilot projects and, thus, speed up field-development decisions. In addition, we will demonstrate a novel workflow to perform this job.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"0703-0718"},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/194367-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42244761","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Organic Acids for Stimulation Purposes: A Review","authors":"Luai Alhamad, Ahmed A. Alrashed, E. Munif, J. Miskimins","doi":"10.2118/199291-PA","DOIUrl":"https://doi.org/10.2118/199291-PA","url":null,"abstract":"\u0000 Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations, and is the base acid that is commonly paired with hydrofluoric acid (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature (HT) can make HCl a poor choice. Alternatively, weaker and less-corrosive chemicals, such as organic acids, can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids.\u0000 This review includes various laboratory evaluation tests and field cases that outline the use of organic acids for formation-damage removal and dissolution. Rotating-disk-apparatus (RDA) results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, coreflooding, inductively coupled plasma, X-ray diffraction, and scanning-electron-microscope (SEM) diffraction tests.\u0000 Because of their retardation performance, organic acids have been used along with mineral acids, mainly a formic/HCl mixture, or as a standalone solution for HT applications. However, the main drawback of these acids is the solubility of reaction-product salts. This challenge has been a limiting factor of using citric acid with calcium-rich formations because of the low solubility of calcium citrate. However, the solubility of the salts associated with formic, acetic, and lactic acid can be increased when these acids are mixed with gluconic acid because of the ability of gluconate ion to chelate calcium-based precipitation. In terms of formation-failure response, organic acids are in lower risk of causing a failure compared with HCl, specifically at deep formation treatments. Organic acids have also been used in other applications. For instance, formic acid is used in HT operations as an intensifier to reduce the corrosion rate caused by HCl. Formic, acetic, and lactic acids can be used to dissolve drilling-mud filter cakes. Citric acid is commonly used as an iron-sequestering agent.\u0000 This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"952-978"},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199291-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41410351","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Modeling the Contribution of Individual Coal Seams on Commingled Gas Production","authors":"Vanessa Santiago, A. Ribeiro, S. Hurter","doi":"10.2118/198241-pa","DOIUrl":"https://doi.org/10.2118/198241-pa","url":null,"abstract":"\u0000 In coal-seam-gas (CSG) fields, where single wells tap multiple seams, it is likely that some of the individual seams hardly contribute to gas recovery. This study aims to examine the contribution of individual seams to the total gas and water production considering that each seam can have different properties and dimensions. A sensitivity analysis using reservoir simulation investigates the effects of individual seam properties on production profiles.\u0000 A radial model simulates the production of a single CSG well consisting of a stack of two seams with a range of properties for permeability, thickness, seam extent, initial reservoir pressure, coal compressibility and porosity. The stress dependency of permeability obeys the Palmer and Mansoori (1998) model. A time coefficient (α) relates seam radius, viscosity, porosity, fracture compressibility, and permeability. It is used to aid interpretation of the sensitivity study. Finally, two hypothetical simulation scenarios with five seams of different thicknesses and depths obtained from producing wells are explored. The range in properties represents conditions found in the Walloon Coal Measures (WCM) of the Surat Basin, relevant to the Australian CSG industry.\u0000 Each seam in the stack achieves its peak production rate at different times, and this can be estimated using α. Seams with lower α reach the peak gas rate earlier than those with higher α-coefficient. The distinct behavior of gas-production profiles depends on the combination of individual seam properties and multiseam interaction. At a αratio > 1 (i.e., αtop/αbottom > 1), the bottom seam peaks first but achieves lower gas recovery than the top seam. An increasing αratio is associated with the inhibition of less-permeable seams and reduced overall well productivity. For αratio < 1, the top seam experiences fast depletion and total gas-production rates decrease drastically. This outcome is confirmed by a more realistic scenario with a higher number of coal layers. Poor combination of seams leads to severe production inhibition of some coal reservoirs and possible wellbore crossflow. The contrast of the seam-lateral extent in the stack and fracture compressibility play an important role in well productivity in the commingled operation of a stack of coal seams. Unfortunately, the lateral extent of individual coal seams is difficult to estimate and poorly known and, therefore, represents a major uncertainty in gas-production prognosis. The αratio analysis is a useful tool to gain understanding of modeled well productivity from commingled CSG reservoirs.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41783236","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Recent Development and Remaining Challenges of Iron Sulfide Scale Mitigation in Sour-Gas Wells","authors":"Tao Chen, Qiwei Wang, F. Chang, N. Aljeaban, K. Alnoaimi","doi":"10.2118/199365-pa","DOIUrl":"https://doi.org/10.2118/199365-pa","url":null,"abstract":"\u0000 Iron sulfide scale deposition can be a significant flow-assurance issue in sour-gas production systems. It can deposit along the water-flowing path from the near-wellbore reservoir region to the surface equipment, which results in formation damage, causes tubing blockage, interferes with well intervention, and reduces hydrocarbon production.\u0000 The main objectives of this paper are to review the new advancements and remaining challenges concerning iron sulfide management in sour-gas wells, covering the mechanisms of iron sulfide formation, the mechanical and chemical removal techniques, and the prevention strategies.\u0000 In this paper we give a special emphasis to the different mechanisms of iron sulfide formation during well-completion and production stages, especially the sources of ferrous iron (Fe2+) for scale deposition. It is essential to understand the root cause to identify and develop suitable technologies to manage the scale problem. We also summarize the latest developments in mechanical methods and chemical dissolvers for the removal of iron sulfide deposited on downhole tubing. The capabilities of the current chemical dissolvers are discussed, and the criteria for effective dissolvers are provided to serve as guides for future development. Then, we provide an overview of recent developments on iron sulfide prevention technologies and treatment strategies. We differentiate the treatment approaches for corrosion byproduct and scale precipitation and scale-inhibitor deployment through continuous-injection and squeeze treatments. Finally, we outline the technical gaps and areas for further research-and-development (R&D) efforts.\u0000 We provide the latest review on iron sulfide formation and mitigation, with an attempt to integrate viable solutions and showcase workable practices.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":"35 1","pages":"0979-0986"},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199365-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45758446","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Pumpdown Diagnostics for Plug-and-Perf Treatments","authors":"D. Cramer, Jon Snyder, Junjing Zhang","doi":"10.2118/201376-pa","DOIUrl":"https://doi.org/10.2118/201376-pa","url":null,"abstract":"\u0000 In this paper, we introduce pumpdown diagnostics, an economical process in which cement sheath integrity, perforation cluster spacing, and fracturing (frac) plug integrity can be assessed for every fracturing stage, potentially leading to improvements in stimulation, completion, cementing, and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pumpdown and perforating operation and correlating the results among multiple fracturing stages and wells in a field or play. A special requirement is that the ball check is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited hydrochloric (HCl) acid coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity.\u0000 Reviews of pumpdown diagnostics field cases from several unconventional plays provide the following insights. Pumpdown diagnostics are time efficient and economical, requiring approximately 15 minutes per fracturing stage. Evaluating communication to the previous fracturing stage can serve as a key performance indicator for treatment control or cement sheath integrity. Pumpdown diagnostic results can be more reliable than cement bond log evaluation, and stage isolation characteristics can be strongly affected by cluster spacing.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":" ","pages":""},"PeriodicalIF":1.2,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44801141","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}