Journal of Petroleum Technology最新文献

{"title":"Study of Field Failures Decodes Hydrogen Embrittlement in High-Strength Coiled Tubing","authors":"C. Carpenter","doi":"10.2118/0624-0052-jpt","DOIUrl":"https://doi.org/10.2118/0624-0052-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218327, “Decoding Hydrogen Embrittlement in High-Strength Coiled Tubing: Insights From Acid-Induced Failures, Field-Data Analysis, and Corrosion-Management Strategies,” by G. McClelland, SPE, Irma I. Galvan, and Genesis L. Mallanao, FET Global Tubing, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Recent reports have highlighted hydrogen embrittlement of high-strength, quench-and-temper (Q&T) coiled tubing (CT) resulting from hydrochloric (HCl) acid usage in sour environments. HCl acid treatments expose CT surfaces to aggressive corrosion, often exacerbated by hydrogen sulfide (H2S) from formation fluids or as a chemical reaction. Helping the CT industry recognize the morphologies of damage when the tube is retired and re-evaluating CT grade selection and chemicals are vital for averting costly and dangerous CT failures. To achieve this goal, a summary of field failures was evaluated from diverse operational environments and locations.\u0000 \u0000 \u0000 \u0000 Failure Case Studies.\u0000 The case studies conclude that failures are generally associated with an acid environment or acid stimulation jobs. In one case, citric acid was mixed with an oxygen scavenger and produced low levels of H2S, causing clear embrittlement and failures on the reel in multiple locations. In several other cases, logistical job delays caused extended acid exposure to the CT, or inhibitor depletion, which, consequently, allowed more hydrogen to enter the steel matrix. Another instance involved unintended H2S exposure in a well which was purportedly sweet. Other investigations indicated a variety of reasons, including recirculated fluids, lack of inhibition or improper use of inhibition, and increased levels of H2S beyond job-planning scenarios.\u0000 Another consistent variable in RCA is lack of pertinent, accurate field information, such as system pH, duration of exposure, timing for acid mixing, acid-decline curves, field consumption of inhibitor pills and timing, field consumption of injection fluids, temperature (surface ambient and downhole), and partial pressure of H2S.\u0000 Failure Modes.\u0000 Hydrogen embrittlement typically is characterized by intergranular cracking along the grain boundaries of the steel. Transgranular embrittlement may manifest itself in some cases. In the samples evaluated, the failure mechanism was observed on both outer-diameter (OD) and inner-diameter (ID) surfaces or was observed as hydrogen gas recombination, resulting in blistering both along the longitudinal weld and in the base Recent reports have highlighted hydrogen embrittlement of high-strength, quench-and-temper (Q&T) coiled tubing (CT) resulting from hydrochloric (HCl) acid usage in sour environments. HCl acid treatments expose CT surfaces to aggressive corrosion, often exacerbated by hydrogen sulfide (H2S) from formation fluids or as a chemical reaction. Helping the CT industry recognize the morphologies of d","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141229958","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":"Sensitivity Analysis of CO2 Minimum Miscibility Pressure Optimizes Gas-Injection EOR","authors":"C. Carpenter","doi":"10.2118/0624-0080-jpt","DOIUrl":"https://doi.org/10.2118/0624-0080-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216683, “Large-Scale, High-Throughput Sensitivity Analysis of CO2 Minimum Miscibility Pressure To Optimize Gas-Injection EOR Processes,” by Ali Abedini, SPE, ZhenBang Qi, SPE, and Thomas de Haas, SPE, Interface Fluidics, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Performance of CO2 injection relies on accurate CO2 minimum miscibility pressure (MMP) and miscibility data at reservoir conditions. A slim tube is the most-reliable tool to measure MMP under different miscibility mechanisms; however, it is very time- and capital-intensive, making it impossible to provide high-throughput data to assess the effect of other gases. Rising-bubble apparatus and vanishing-interfacial-tension techniques are cheaper and easier to run, but these methods are unable to capture different miscibility mechanisms fully. In the case study presented in the complete paper, the authors present a highly efficient microfluidic platform to measure, in a faster and easier manner, high-quality MMP data of CO2 with various impurities significantly.\u0000 \u0000 \u0000 \u0000 Conducting miscibility tests at high pressure or high temperature with live oil samples and real gas mixtures requires a platform capable of handling complex fluid systems at reservoir conditions. An advanced microfluidic system was used to perform a large set of miscibility/MMP tests to investigate the role of different impurities on the MMP of pure CO2 with an oil sample from a depleted reservoir in Alberta. The results reported demonstrate the capabilities of the new microfluidic approach to provide fast and accurate high-volume miscibility and MMP data for a wide range of gas compositions unobtainable by conventional methods.\u0000 \u0000 \u0000 \u0000 The portable microfluidic platform integrates fluid-control, microfluidic, and imaging systems, enabling performance of a series of miscibility and MMP measurements (Fig. 1a). The platform is equipped with three high-pressure pumps to control gas injection, oil injection, and backpressure. The gas sample, oil sample, and effluent are stored in sample bottles heated with a heating jacket and connected to the pumps. The valves and tubing are placed in a valve box that heats up internally. The manifold is the holder for the microfluidic chip and consists of bottom and top pieces that sandwich the chip. The bottom of the manifold is controlled by a hydraulic pump. The time-lapse imaging is performed using a microscope equipped with a high-resolution camera. Fig. 1b shows the microfluidic chip and the porous media design. The serpentine porous media, with a total length of 57 cm, contains circular pillars to promote multiple contacts in the system.\u0000 Table 1 of the complete paper contains the list of the gases used in this study. The composition of the recycled gas includes approximately 86% CO2, approximately 7.7% methane, and other impurities.\u0000 To validate the accuracy of the microfluidic MM","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141279798","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":"Model Captures Carbonate Matrix Acidizing in Horizontal Well Completions","authors":"C. Carpenter","doi":"10.2118/0624-0061-jpt","DOIUrl":"https://doi.org/10.2118/0624-0061-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23178, “A Comprehensive Model for Carbonate Matrix Acidizing in Complex Horizontal Well Completions,” by Mahmoud T. Ali, Ahmed Zakaria, SPE, and Jiliang Wang, Baker Hughes, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 The complete paper presents an extensively validated model to simulate acid flow from the wellhead to the wormhole tip in carbonate formations. The model accounts for upper and lower completion wellbore hydraulics, pressure drop across valves, annular flow, and wormhole growth. The comprehensive model introduced in this work provides stimulation engineers with a reliable tool to design successful acid stimulation jobs in complex horizontal well completions.\u0000 \u0000 \u0000 \u0000 Prediction and analysis of wormhole growth and the corresponding skin relies on the ability to predict the reservoir-face pressure and the understanding of physics and chemistry of acid flow in porous media. In many situations, reservoir-face pressure must be predicted from surface treating pressure. In some situations, a downhole gauge may be set at the bottom of the upper completion. In certain horizontal wells, however, the reservoir face can be far from the downhole gauges and detailed mathematical models still are required for accurate reservoir-face pressure calculations.\u0000 The travel of the treatment fluids from the well surface through tubulars is accompanied with pressure losses caused by friction with the walls and pressure gain caused by the change in vertical depth. The flow through the horizontal section of the well is controlled by the friction calculations. In the lower completion, the fluid needs to travel radially, usually through limited entries to the reservoir. The simplest completion is the open hole, where fluid travels radially to the reservoir face with no mechanical constraints. In advanced completions, the fluid must go through orifices or more complicated pathways such as an inflow control device (ICD) before hitting the reservoir face. Mathematical models are needed to account for the frictional losses through those mechanical constraints. In many cases, one ICD can be used to stimulate more than 200 ft of the reservoir, which requires the implementation of advanced algorithms to account for the flow behind the ICD and distribute the fluid precisely.\u0000 Once the fluid reaches the reservoir face with the accurate pressure, then, using the classical production-engineering equations, the injection rate can be calculated for each zone. Acids usually are injected in carbonate formations to create thin tunnels, called wormholes, to bypass damage and improve well productivity or injectivity. An experimentally validated model was implemented to predict the wormhole growth as a function of rate, acid type, concentration, temperature, rock type, and mineralogy. The generated wormholes were ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141234998","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":"Comments: Shell Fuels Heavy-Metal Band’s Tour in Europe","authors":"P. Boschee","doi":"10.2118/0624-0008-jpt","DOIUrl":"https://doi.org/10.2118/0624-0008-jpt","url":null,"abstract":"\u0000 \u0000 Metallica, an iconic American heavy metal band, began the European leg of its M72 World Tour in Europe on 24 May, rocking in Munich, Germany. Although their high-decibel signature guitar riffs, dynamic drumming, and fast tempos have been widely celebrated and anticipated, their tour buses have attracted their own dedicated groupies.\u0000 These groupies are interested in the alternative fuels keeping the buses rolling on the 2-month, 7,200-mile journey across nine countries and include Shell, big-rig and electric vehicle manufacturers, and producers of hydrogen, biofuels, and LNG.\u0000 The band’s gear will be hauled using a diverse fleet of special-edition vehicles built by Italian manufacturer Iveco. Ten Iveco S-Way heavy-duty natural gas vehicles and four S-Way trucks powered by renewable diesel will utilize Shell’s refueling network. The fleet will include a convoy for additional logistics and show support, comprising two S-eWay trucks—the first fully electric heavy-duty trucks manufactured by the company—two S-Way LNG trucks, and one more S-Way powered by renewable diesel. An S-eWay fuel-cell truck will also join the convoy for the final Spanish dates. Iveco’s sister brand, Iveco Bus, will shuttle the band’s crew on-site at the venues with eDaily minibuses and an Evadys coach.\u0000 Shell’s renewable diesel, BioLNG, LNG, and FuelSave diesel will be used in the trucks. Iveco’s hydrogen fuel-cell trucks are powered by fuel-cell systems from HTWO, a hydrogen business brand of Hyundai Motor Group, and use hydrogen produced by Air Liquide.\u0000 The truck manufacturer displayed its first prototype of a heavy-duty fuel-cell truck in June 2023 during the opening of Air Liquide’s hydrogen refueling station in Fos-sur-Mer (Marseille). The large-capacity high-pressure station (1 ton/day) is supplied with hydrogen through pipeline and features a fast refueling time at 700-bar pressure.\u0000 The Fos-sur-Mer station is part of the HyAMMED project supported by French funding. The new station is also part of H2Haul, the European project cofinanced by the Clean Hydrogen Partnership. Air Liquide and Iveco were among the first partners of the H2Haul project when it was launched in 2019. A second high-capacity station (700 bar, 2 tons/day) dedicated to heavy vehicles will be installed in Salon-de-Provence to supply a potential fleet of 50 hydrogen Iveco trucks from 2025 as part of the R’HySE project which aims to deploy new infrastructure to distribute hydrogen sources in the south of France.\u0000 \u0000 \u0000 \u0000 Although Europe has available more alternative-fuel infrastructure than the US, Metallica’s route is experiencing some issues.\u0000 The longest leg of the journey will be from Warsaw to Madrid, about 1,800 miles. Consider the following ranges of the Iveco tour trucks: EV models, 311 miles; LNG 994; and fuel cell EVs, 500.\u0000 Iveco CEO Gerrit Marx said in a recent Wall Street Journal article that the lack of charging and fueling stations between venues means the battery-electric and hydrogen","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141231061","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study Explores Effect of Solids on Topside Operations in an EOR Context","authors":"C. Carpenter","doi":"10.2118/0624-0086-jpt","DOIUrl":"https://doi.org/10.2118/0624-0086-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216848, “Impact of Solids on Topside Operations in EOR Context,” by Christian Blázquez, Marie-Hélène Klopffer, SPE, and Eric Kohler, IFP Energies nouvelles. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The presence of solids in hydrocarbon treatment and separation equipment downstream of the choke can have a significant effect on process operability, assets risks, and flow assurance, therefore affecting operational economics. In the complete paper, the effect of solid particles on oil/water (O/W) separators (i.e., emulsion stability) and on produced-water treatment\u0000 has been studied.\u0000 \u0000 \u0000 \u0000 In this study, six different solids were chosen, three representing reservoir solids (sand, illite, and kaolinite) and three for scale and corrosion solids [calcium carbonate (CaCO3), barium sulfate (BaSO4), and iron sulfide (FeS)]. All solids used were characterized in terms of composition and size; for modified solids, their wettability also was measured. The sand sample was fully water-wet, while the wettability of the CaCO3 and the BaSO4 could not be measured. For the rest of the particles, contact angles lower than 90° showed water-wet properties.\u0000 A crude oil from offshore Brazil was used. The oil is a heavy one that is quite viscous at normal conditions. The oil also is acidic with high content in polar components. The polymer used is xanthan gum.\u0000 \u0000 \u0000 \u0000 The ability of the solid particles to stabilize O/W emulsions depends on several factors, such as particle concentration, size, shape, and wettability. During this work, the evaluation of the effect of the selected particles on the stabilization of a 50% water-cut emulsion was performed in two steps. Before studying the effect of different solids on O/W separation in the presence of xanthan, the effect of solid concentration and nature was investigated through rapid emulsion tests. Afterward, the most-troublesome particle concentrations were evaluated in the presence of polymer and demulsifier.\u0000 Effect of Solids Without Polymer.\u0000 The rapid emulsion test was developed based on Tessari’s test method for the formation of medical foams. The basic principle is to produce an emulsion by forcing the oily and the aqueous phases to repeatedly experience a restriction. The resulting emulsion is poured into a glass tube. The experimental temperature is 50°C, and the water cut is 50%.\u0000 O/W separation kinetics are followed for 60 minutes. In addition, the oil-in-water at the end of the test is evaluated by visual comparison with the reference case (no chemical analysis is performed during this phase).\u0000 The effect of the solid particles on O/W separation depends not only on their nature but also on their concentration.\u0000 Reservoir Solids.\u0000 The presence of sand did not affect separation performance, presumably because of the large granulometry and reduced surface area. The sand settled quickly to the bottom of the flask","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141230322","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":"True Rig Automation Stymied by Lack of Interoperable Drilling Tools, but Industry Study Offers a Way Forward","authors":"Trent Jacobs","doi":"10.2118/0624-0026-jpt","DOIUrl":"https://doi.org/10.2118/0624-0026-jpt","url":null,"abstract":"A recent industry study argues that despite 2 decades of progress, the oil and gas industry’s drive toward drilling automation is staring at a bottleneck that threatens to stifle future innovation.\u0000 Authored by professionals from the Drilling and Wells Interoperability Standards (D-WIS) work group, IADC/SPE 217748 puts the spotlight on systems interoperability—or rather, the lack of it.\u0000 The paper brings together expertise from big players such as Noble Drilling, Hess Corp., and Baker Hughes, among others. The group was formed in 2020 under the SPE Drilling Systems Automation Technical Section (DSATS) and its recommendations reflect the input of more than five dozen entities, including most of the supermajors, the big four service companies, the world’s largest drilling contractors, and several smaller technology and research groups.\u0000 D-WIS points out that the automation tech we’ve seen hit the market so far has been limited to distinct components and segments of the well-construction process. Notable advancements include automation offerings for pipe handling, rotary steerable systems, and rate of penetration.\u0000 Such innovations have taken people out of harm’s way, lowered drilling costs, and helped make better wellbores. However, they are standalone, isolated applications that generally do not interact with each other unless they are owned by the same company.\u0000 According to the new D-WIS study, reaching the next level of drilling efficiency through a truly automated system requires data to be shared seamlessly between different rig technologies regardless of the manufacturer.\u0000 The workgroup’s authors assert that not only have the low-hanging fruits been largely picked when it comes to making major gains in well construction but that “the current siloed approach has begun to reach its limits and is consuming capital and resources.”\u0000 Reasons why interoperability on the rig doesn’t already exist range from concerns over the exposure of proprietary information to third parties, to a lack of incentives for equipment makers and service providers to oblige. There’s also the age-old tradition of resisting change.\u0000 D-WIS is making the case that working past these obstacles will clear the way for a new generation of advisory and drilling process software to be deployed at unprecedented speed and scale. The linchpin for this progress is a common interface standard that will transform disparate technologies into easily integrable plug-and-play components.\u0000 To achieve its ambitious goal the industry group has outlined a dual-path strategy that tackles both the technical requirements and commercial risks.\u0000 In the near term, the group is encouraging companies to adopt ISA-88, an industrial control standard already relied upon by many heavy industries. An additional step calls for the development of an Application Programming Interface (API) that facilitates communication between automated drilling control systems (ADCS) and external advisory software.\u0000 For the","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141229405","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study Reviews Multilateral Installation Improvements on the North West Shelf","authors":"C. Carpenter","doi":"10.2118/0524-0100-jpt","DOIUrl":"https://doi.org/10.2118/0524-0100-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32910,“A Decade of Multilateral Technology Installation Improvements Down Under,” by Stefano Cappiello and Adam Pasicznyk, SPE, Halliburton. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference.\u0000 \u0000 \u0000 \u0000 Multilaterals wells on the North West Shelf of Australia have been installed for over a decade. An overview of the well architecture, technology evolution, reliability, and efficiency of these operations is presented in the complete paper. The study is focused on subsea multilateral campaigns, where multiple global and regional first installations took place in mature fields.\u0000 \u0000 \u0000 \u0000 Multilateral developments in Australia mainly have been completed off subsea installations, with fewer performed from jack-up rigs. These multilateral completions mostly have been installed with the junction located in the producing reservoir sands. Technology Advancement of Multilaterals (TAML) Level 5 completions have successfully been deployed.\u0000 The authors classify related systems as follows, with the most attention paid in the synopsis to the final two classes:\u0000 - Generation One (Field A)\u0000 - Generation Two (Field B)\u0000 - Generation Three (Field C)\u0000 - Generation Four (Field A)\u0000 \u0000 \u0000 \u0000 Because of sand production within the reservoir, these applications typically require a TAML Level 5 completion system. These systems deliver hydraulic and mechanical isolation at the junction through the completion. The junction is isolated above and below by production packers and by swell packers in the lateral. The junctions typically are installed horizontally within the reservoir.\u0000 The original general requirements to construct Level 5 multilateral junctions included the following:\u0000 - Ability to construct a Level 5 Junction in the 9⅝-in. casing or liner\u0000 - Ability to run a landing profile or coupling as part of the 9⅝-in. production casing or liner\u0000 - Ability to run and orient a premilled window at depth\u0000 - Drill-out 8½-in. openhole section into the mainbore and into the lateral\u0000 - Junction installed within the reservoir at high angle\u0000 - Window milling to be performed in one trip\u0000 - Lateral completion to be installed in one trip\u0000 - Compressive strength rating capable of running screen sections over 2 km\u0000 As the operators began to adopt multilateral technology in Australia, the following requirements were incrementally added:\u0000 - Ability to deliver a Level 5 multilateral system in an existing well\u0000 - Ability to deliver a trilateral well\u0000 - Improve efficiency and reduce installation time\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141057970","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":"Foamed Cement Mitigates Gas Migration in Shallow Thermal Wells in Alberta","authors":"C. Carpenter","doi":"10.2118/0524-0112-jpt","DOIUrl":"https://doi.org/10.2118/0524-0112-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214768, “Mitigating Gas Migration Using Foamed Cement on Shallow Thermal Wells in Northeast Alberta,” by Charles Sylvestre, SPE, Sanjel Energy Services; Julio Oliveira, Suncor Energy; and Heyong Jiao, Sanjel Energy Services. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 A foamed cement solution was designed and implemented to cement shallow intermediate casing strings in a heavy oil play in northeast Alberta after conventional area-specific cementing solutions could not prevent surface casing vent flows. Foamed cement was pursued as a better alternative technical solution and ultimately led to its successful placement in the field. Significant technical and operational hurdles were overcome to confirm proper well control and ensure that the energized cement could be pumped safely and effectively.\u0000 \u0000 \u0000 \u0000 MacKay River is Alberta’s shallowest steam-assisted gravity drainage (SAGD) project, with wells typically ranging between 100 m and 150 m true vertical depth (TVD). Wells have been drilled recently at MacKay River with a horizontal length approaching 1000 m and total length exceeding 1500 m measured depth (MD). Wells at MacKay River are drilled using a slant rig because of the extremely shallow depth of the reservoir. The wells feature a three-string casing design with a shallow surface casing, an intermediate casing that runs from surface to the target formation and is landed at 90° inclination, and a horizontal production (or injection) liner hung off the intermediate casing. The intermediate casing is cemented in place and uses premium connections incorporating a metal-to-metal seal to provide a barrier between wellbore fluids and the formations overlying the reservoir.\u0000 The complete paper discusses a new pad at the MacKay River SAGD operating site. The specific operations discussed are those involving intermediate cementing.\u0000 \u0000 \u0000 \u0000 One of the most unusual features of the case wells was the discovery of gas trapped under a shallow formation at approximately 80–100 m vertical depth. The pad adjacent to this new pad has been in operation for 17 years.\u0000 The second obstacle was the hole and casing size, which creates a large annulus. The open hole size was designed at 374.7 mm with the intermediate casing sized at 298.5 mm. This creates an annular gap of 38.1 mm in a gauge hole, but typically these wells require 150% cement excess to achieve cement returns to surface, meaning that, in certain areas of the well, the annulus is much larger. The next challenge presented by the case wells is that they are slanted wells, spudded at an angle of approximately 45° from the surface.\u0000 The low temperature of these wells also adds to the complexity of preventing gas flow. At such low temperatures, cement sets much slower than in other well types.\u0000 Finally, the shallow nature of the well, landing at only 113 m vertical depth, does not allow effective hydrostatic ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141034508","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":"Intelligent Completion Enables Zonal Isolation Offshore Malaysia","authors":"C. Carpenter","doi":"10.2118/0524-0074-jpt","DOIUrl":"https://doi.org/10.2118/0524-0074-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22882, “Advancement of Openhole Gravel Pack and Zonal Isolation With Selective Intelligent Completion in Deepwater Malaysia,” by Elvy Samuel, SPE, Noppanan Nopsiri, and Lee Chan Fong, PTTEP, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 As fields mature, drilling and completion design and execution for infill development become more challenging. In a deepwater environment, one strategy is to target several reservoir packages in a single wellbore. This technique frequently presents technical challenges, however, because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. The complete paper presents a completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K.\u0000 \u0000 \u0000 \u0000 The SNP Field is 125 km offshore Sabah in approximately 1350–1400 m water depth. The field crosses the boundary between Block K and Block G, approximately 15 km from the Kikeh floating production, storage, and offloading (FPSO) facility. The field commenced Phase 1 in 2011 with the completion of nine oil producers as openhole gravel packs (OHGPs) and five water injectors with expandable sand screens at the sandface. Phase 2 development, partially covered in the complete paper, commenced in the third quarter of 2021 with three standard oil producers and one smart producer well.\u0000 All SNP Phase 2 wells were completed as OHGPs targeting various sand reservoirs in a common pressure regime. The well discussed in the complete paper addressed subsurface uncertainties related to depth and the pressure differential between the upper zone (UZ) and the lower zone (LZ) and the isolation requirements of the middle zone (MZ) by implementing an intelligent completion architecture with an OHGP with zonal isolation on the sandface. The flow diversion between the producer zones would be achieved through the deployment of an intermediate completion coupled with an intelligent completion architecture in the upper completion.\u0000 The well was placed on production in the first quarter of 2022 to the Kikeh FPSO, achieving the targeted rates solids-free.\u0000 \u0000 \u0000 \u0000 In this field, the fracture pressure window is marginal, suggesting that a conventional OHGP approach would be challenging. Adding to this complexity is the zonal-isolation requirement. To achieve the objective of complete openhole (OH) coverage and to enable zonal isolation simultaneously, shunt-tube technology was identified as critical. The selection of shunt-tube technology allows the following achievements:\u0000 - Premature screenout mitigation, because the technique is a proven system that enables the slurry to bypass any restriction in the OH/screen annulus\u0000 - Zonal-isolation capabilities by combining shunted sand screens and OH mechanical packers wit","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141057955","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":"High-Intensity Hydraulic Fracturing May Hold Off US Gulf Oil Declines, but Shell Study Reveals That It’s No Easy Feat","authors":"Trent Jacobs","doi":"10.2118/0524-0028-jpt","DOIUrl":"https://doi.org/10.2118/0524-0028-jpt","url":null,"abstract":"\u0000 \u0000 When stimulating oil wells in the ultradeep Lower Tertiary play, “It is impossible to do too much contingency planning.”\u0000 Those words rank high in a new study by Shell that shows how it has borrowed a page from the unconventional revolution to create “massive hydraulic fractures” in some of the deepest wells ever drilled in the Gulf of Mexico.\u0000 Only a handful of operators can claim to have any experience in this area, but with more looking to follow suit the profile of US Gulf production may soon look a lot different.\u0000 A separate study by Enverus Intelligence Research highlights that since 2016, at least 27 multistage hydraulically fractured wells have been completed in the Lower Tertiary, also called the Paleogene.\u0000 That accounts for about half of all wells producing from the low-permeability trend defined by interbedded sandstones and shales that in the central US Gulf are found 5 to 6 miles below sea level.\u0000 Enverus forecasts that as the share of fractured wells rises, Lower Tertiary production will more than double from 270,000 B/D in 2023 to 750,000 B/D by 2028. The market intelligence firm predicts such a surge will offset much of the anticipated declines from older Gulf projects and stabilize the region’s output at nearly 2 million B/D throughout the decade.\u0000 The trailblazers are led by Chevron with 14 fractured wells at its Jack/St. Malo project followed by Shell with nine at the Great White unit and the Stones field, which at a water depth of 9,500 ft, is host to the world’s deepest production facility. The elite group is rounded out by US independent LLOG, which has three high-intensity fractured wells in the Buckskin field, and ExxonMobil with one in its Julia development.\u0000 “Over the past decade the belief was that much of the Lower Tertiary would be subcommercial because many of the discoveries were around 5 to 15 md, which in the offshore context is considered super tight,” Marvin Ma, an analyst at Enverus, said. “But based on the experiences we’re seeing from Chevron and Shell, I think operators are starting to realize that it is possible to develop these projects commercially.”\u0000 Indeed, the numbers shared so far are hard to ignore.\u0000 Early production rates reported from some of the newest Lower Tertiary fractured wells have ranged between 15,000 and 22,000 B/D.\u0000 And while poor results have been seen, Enverus believes the estimated ultimate recoveries (EURs) of many fractured wells ranges from 18–73% above the group with traditional completions. These figures translate to 6 to 10 million bbl of incremental crude.\u0000 \u0000 \u0000 \u0000 If large-scale fracturing is the key to commercial success in the Lower Tertiary, it will not come easy.\u0000 The remoteness poses cumbersome logistical challenges while the pressures involved with running a frac job in deepwater wells requires far more planning and modeling than usual.\u0000 Ken Lizak, a completions advisor at Shell, said his team has reaped the rewards of this due diligence but noted future improvements ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141032732","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}