Journal of Petroleum Technology最新文献

{"title":"Study Examines Limitations of CCS and Their Effect on Oil and Gas Production","authors":"C. Carpenter","doi":"10.2118/0724-0102-jpt","DOIUrl":"https://doi.org/10.2118/0724-0102-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214950, “Limitations and Fallacies of Carbon Capture and Storage and Impact on Oil and Gas Production,” by S.M. Farouq Ali, SPE, and Mohamed Y. Soliman, SPE, University of Houston. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 In the complete paper, the authors write that, while carbon capture and storage (CCS) initiatives are affecting oil and gas operations profoundly, such efforts have had little perceptible effect on atmospheric CO2, which continues to increase. The paper aims to show that current CCS regimens have serious technical and fiscal constraints and questionable validity, stating that, globally, CCS has not increased beyond approximately 0.1% of global CO2 emissions in the past 20 years. The paper offers partial solutions and concludes that, while oil and gas will continue to be important energy sources beyond the foreseeable future, oil companies will accomplish the needed CCS.\u0000 \u0000 \u0000 \u0000 The authors write that, while CCS efforts have been pursued for 4 decades, little has been achieved. For the past 20 years, the percentage of CO2 captured and stored is less than 0.1% of the CO2 emitted worldwide, if one considers CO2 enhanced oil recovery (EOR) projects to be CSS—which, the authors write, is a fallacy. They emphasize that CCS means injection with no production. The key to CCS success, they write, is major governmental subsidization, by whatever terminology it is known, and that means taxpayer money. Sweeping decisions that have a profound effect on oil and gas production and petroleum engineering education are being made based on predictions of an increase in CO2 concentration in the atmosphere in various time frames.\u0000 \u0000 \u0000 \u0000 The problem of world CO2 emissions capture is gigantic. To appreciate the magnitude of the problem, imagine that 1 year’s CO2 emissions (40 billion tonnes) are captured, compressed and liquified, and injected into a reservoir the size of the Ghawar oil field, the largest reservoir in the world, with the entire pore space (approximately 0.5 Tcf) available for storage. In this hypothetical, nine such reservoirs would be required every year. Presumably, such storage space can be found, but collecting the CO2 and bringing it to a storage site is a highly complex task. For example, in a sequestration effort in a building complex in New York, the CO2 is separated, liquified, and trucked to a storage site to be injected underground, which is impractical. Often, the example of the Nordic countries (mainly Denmark, Sweden, and Norway) is cited as evidence of successful emissions reduction. But the total population of these countries is approximately the same as that of metropolitan Mumbai in India.\u0000 \u0000 \u0000 \u0000 Carbon capture use and storage (CCUS) implies that the CO2 produced by various processes is captured and used for EOR. This accounts for approximately 30% of the 230 mtpa of CO2 captured globally. CCS means that any CO2 pr","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141709759","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 Reservoir Engineering Aspects of Geologic Hydrogen Storage","authors":"C. Carpenter","doi":"10.2118/0724-0108-jpt","DOIUrl":"https://doi.org/10.2118/0724-0108-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission.\u0000 \u0000 \u0000 \u0000 Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute.\u0000 \u0000 \u0000 \u0000 The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available.\u0000 Reservoir Engineering of GHS.\u0000 GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs.\u0000 GHS in SCs.\u0000 SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage.\u0000 The storage capacity of caverns in Germany is determined by their volume","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141701980","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":"Advancing Water Deoiling Efficiency in Petroleum Production: A Comprehensive Case Study of Hybrid Flotation Technology Integration","authors":"R. White, A. Alhamoud","doi":"10.2118/0724-0058-jpt","DOIUrl":"https://doi.org/10.2118/0724-0058-jpt","url":null,"abstract":"\u0000 \u0000 The efficient management of increasing water cuts in oil fields is paramount for sustaining profitability and minimizing environmental impact. This article presents a comprehensive case study conducted by Saudi Aramco, focusing on the integration of hybrid flotation technology into a gravity water/oil separator (WOSEP) to enhance deoiling efficiency and reduce operational costs and carbon emissions.\u0000 The retrofit involved merging enhanced gravity separation with induced gas flotation (IGF) within the same vessel, resulting in significant improvements in deoiling capacity, outlet oil-in-water content reduction, and operational efficiency. Detailed insights into the design, operation, and performance of hybrid flotation systems are provided, offering valuable guidance for similar initiatives in the petroleum industry.\u0000 \u0000 \u0000 \u0000 Petroleum production facilities face escalating challenges with increasing water-production rates during crude-oil extraction, particularly in waterflooding operations for secondary oil recovery. This trend not only escalates operational costs but also intensifies environmental concerns, particularly regarding energy consumption and carbon emissions associated with water-handling processes.\u0000 In response to these challenges, Saudi Aramco embarked on a pioneering initiative to enhance water-deoiling efficiency by integrating hybrid flotation technology into a conventional gravity WOSEP.\u0000 This case study presents a comprehensive analysis of the design, implementation, and outcomes of this transformative project, offering valuable insights for the broader petroleum industry.\u0000 \u0000 \u0000 \u0000 The upgrade process commenced with an assessment of the existing WOSEP system and its operational challenges. Recognizing the impending capacity constraints and escalating oil-in-water content, Saudi Aramco’s engineering team opted for a holistic approach that combined enhanced gravity separation with IGF within the same vessel. The retrofit involved reconfiguring the internal components of the WOSEP to accommodate the hybrid flotation system, including the installation of advanced plate-pack internals for gravity separation and the integration of IGF cells for additional oil removal. Rigorous testing and optimization procedures were conducted to ensure seamless integration and optimal performance of the hybrid system.\u0000 \u0000 \u0000 \u0000 In a typical gas/oil separation plant, the initial phase involves the extraction of crude oil, associated gas, and produced water from wells via a production manifold. These constituents are then directed to a three-phase separator, also known as a high-pressure production trap (HPPT). In the HPPT, free water droplets are separated from the oil through gravity separation, aided by demulsifier injection at the production header. The separated free water is discharged to a WOSEP, typically a gravity separator, for deoiling.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699987","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":"Nonmetallic-Based Tubulars Provide Superior Integrity, Cost Savings","authors":"C. Carpenter","doi":"10.2118/0724-0082-jpt","DOIUrl":"https://doi.org/10.2118/0724-0082-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214647, “Operational Experience From the Implementation of 21 Wells With Nonmetallic-Based Downhole Tubing: From Pilot to Large-Scale Implementation,” by Mohamad H. Ahmad, ADNOC. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Tubular glass-reinforced-epoxy (GRE) lining technology has been applied globally since the 1960s in eliminating downhole tubular corrosion. Compared with conventional carbon steel, which can experience frequent failure, GRE-lined carbon steel provides long-lasting protection, resulting in huge savings in life-cycle cost. The operator implemented this technology for a successful trial of water-disposal wells. In the complete paper, the authors share the data from caliper logs run into, and the inspection of tubing pulled from, these disposal wells after 4 years in service.\u0000 \u0000 \u0000 \u0000 A growing emphasis on water disposal was inevitable because so much water was being produced with increased water cut and production. ADNOC Onshore operates almost 200 water-disposal wells. However, corrosion has been a common problem in these wells, such that a failure has been reported every 1–2 years.\u0000 Use of corrosion-prone carbon steel for disposal strings has led to integrity issues and the need for expensive workover jobs that could cost between $1.5 million and $2 million per job.\u0000 \u0000 \u0000 \u0000 Since 2014, the operator has run 19 water-disposal wells with GRE-lined carbon steel strings. No failures have been reported, and inspections have been successful.\u0000 Fiberglass tubular lining protects the internal surface of the tubing or casing inside the steel joint. Cement is pumped into the annulus between the GRE-liner outer diameter (OD) and the steel‑pipe inner diameter (ID). The final product is a completely corrosion-protected string, even under the connection area, where accessories called flares and corrosion barrier rings (CBRs) are installed (Fig. 1). The mechanical capability of the system is maintained by the steel pipe, while the internal fiberglass liner provides reliable corrosion resistance.\u0000 Fiberglass Liner.\u0000 The fiberglass liner shows excellent resistance in corrosive environments. As per tested and as per the manufacturer’s data sheets, the fiberglass lining system can be used in temperatures of up to 145°C, depending on hydrogen sulfide and CO2 levels in the flowing fluid.\u0000 Besides being corrosion‑resistant, fiberglass lining improves the flow rate of the flowing water or oil because of the superior surface-energy properties and manufacturing quality of the liner material. The thickness of the liner varies according to the tubing size (diameter).\u0000 Cement.\u0000 The cement transfer applies pressure directly to the steel pipe. The cement does not bond the fiberglass liner to the steel and allows relative micromovement between the fiberglass liner and the steel pipe resulting from the difference in the thermal expansion coefficient of these two ma","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141716719","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":"Azerbaijan—The Land of Unquenchable Fire","authors":"Patricia Szymczak","doi":"10.2118/0724-0018-jpt","DOIUrl":"https://doi.org/10.2118/0724-0018-jpt","url":null,"abstract":"\u0000 \u0000 For millennia, Zoroastrian fire worshippers traveled on pilgrimage to pray at temples built where methane seeping from deep underground caused flames to burst from the earth on the Absheron Peninsula near Baku, the capital of today’s Azerbaijan.\u0000 The Venetian merchant Marco Polo observed such mysterious fires and puddles of oil that bubbled or even gushed as fountains to the surface as he trekked along the Silk Road through the Caucasus Mountains in the 13th century.\u0000 In a travelogue written in 1298, The Travels of Marco Polo, he is said to have described: “Near the Georgian border there is a spring from which gushes a stream of oil in such abundance that a hundred ships may load here at once. This oil is not good to eat, but it is good for burning and as a salve for men and camels affected with itch or scab.”\u0000 He was referring to the Khanates of Azerbaijan, a part of the Persian Empire in Marco Polo’s time but absorbed in 1806 into the Russian Empire whose czars took an interest in financing early oil production—hand dug and exported on camel back. Its high paraffin content was valued for producing kerosene lamp oil and lubricants including cannon grease.\u0000 \u0000 \u0000 \u0000 As the Industrial Revolution swept from West to East in the mid-19th century, many of the innovations and business systems around which the modern oil and gas industry were soon to coalesce were tested in the ancient “Land of Fire.”\u0000 Czar Nicholas I (1825–1855) financed the world’s first mechanically drilled oil well in 1846 using a cable-tool percussion drilling method. A 21-m-deep (69 ft) exploration well was the result. This happened a decade before Edwin Drake added steam-engine power to a mechanical drill to put Titusville, Pennsylvania, on the map in 1859, as described in the Branobel History archives.\u0000 By 1871, with Nicholas’ son, the reformer Alexander II now on the Russian throne, boreholes had replaced buckets across the Bibi-Heybat and Balakhani oil fields.\u0000 The arrival from Sweden in the 1870s of Alfred Nobel’s brothers, Ludvig and Robert, brought a step change to Azerbaijan in terms of industrial innovation, construction, and logistics such that by 1900 Azerbaijan was producing 50% of the world’s oil, historical sources agree.\u0000 Alexander II had abolished the state monopoly on oil production in 1869, opening the door to foreign industrialists and their capital.\u0000 Robert Nobel obliged and opened the joint stock Branobel Co. in 1878 with a partner from a weapons plant in the Russian town of Izhevsk. He put down share capital of 3 million rubles ($30,000 in today’s money) to register Tovarishestvo Neftyanogo Proizvodstva Bratyev Nobel—in English, The Brothers Nobel Paraffin Production Company (aka Branobel).\u0000 The transformation of Baku’s oil fields into a capitalist production sector had begun in 1872 with the auction of 15 blocks in the Balakhani oil field and two blocks in Bibi-Heybat, according to a history prepared by Azerbaijan’s Ministry of Energy in 2020.\u0000 This drove a","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141709380","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":"Integrated Multiphase-Flow Modeling Technique Yields Accurate Downhole Pressure Predictions","authors":"C. Carpenter","doi":"10.2118/0724-0074-jpt","DOIUrl":"https://doi.org/10.2118/0724-0074-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214855, “Integrated Multiphase-Flow Modeling for Downhole Pressure Predictions,” by Abdullah Alkhezzi and Yilin Fan, SPE, Colorado School of Mines. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 This work presents an integrated multiphase flow model for downhole pressure predictions. The aim of the model is to produce more-accurate downhole pressure predictions under wide flowing conditions while maintaining a simple form. As a component of the integrated model, an improved two-fluid model for segregated flow is proposed. Results of the two-fluid segregated model are compared with five state-of-the-art existing models, while results of the integrated model are compared with three models.\u0000 \u0000 \u0000 \u0000 Throughout the life of the well, knowing bottomhole flowing pressure (Pwf) and the pressure profile of the wellbore are of great significance. Unfortunately, deploying downhole pressure gauges to obtain Pwfreadings is often not economical or practical. The common practice is to apply hydraulic models to predict Pwfgiven surface measurements. The prediction of such behavior is simple when dealing with single-phase fluid flow. Unfortunately, this condition is rare in the petroleum industry.\u0000 The existence of multiple phases introduces multiple complexities hindering the accuracy of downhole pressure predictions. To account for such variations, fluid-property models must be integrated into the calculation procedure. The complexity, coupled with field-data scarcity, results in the deficiency of work that evaluates point models on actual wells.\u0000 In this work, the authors evaluated the performance of a few widely used multiphase-flow point-based models on actual field data using a marching algorithm and developed a simplified, yet more precise, integrated model.\u0000 \u0000 \u0000 \u0000 Data Set Description.\u0000 In this study, data points were collected for two main purposes. First, experimental data sets were collected to model and improve the segregated flow model. Second, field data were collected to test the integrated multiphase model. To improve the segregated flow model, 1,478 experimental data points were obtained from various sources in the literature.\u0000 To evaluate the integrated multiphase flow model, 313 data points from two main sources of data were used (literature and actual field data). In total, four data sets were obtained from the literature and one was obtained from Civitas Resources.\u0000 Integrated Model Description.\u0000 The multiphase-flow point model incorporated in the authors’ integrated modeling consists of three main components: critical gas velocity estimation for the onset of liquid loading and hydraulic multiphase flow models before and after the onset of liquid loading. The proposed model characterizes the flow based on whether liquid loading occurs.\u0000 The onset of liquid loading corresponds with the transition of the flow pattern from segregated to intermittent ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141707789","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":"Partnerships Crucial in Developing Nonmetallic Downhole Tubulars","authors":"C. Carpenter","doi":"10.2118/0724-0079-jpt","DOIUrl":"https://doi.org/10.2118/0724-0079-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23491, “Role of Ecosystem Partners To Make Nonmetallic Downhole Tubulars a Reality,” by Ahmed Aladawy, SPE, and Ameen Malkawi, SPE, Baker Hughes, and Omar El Shamy, SPE, Novel Non-Metallic Solutions. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 Nonmetallic (NM) downhole tubulars offer a longer lifetime than their steel counterparts while eliminating corrosion concerns and lowering total cost of ownership. Making them a reality, however, requires a rigorous ecosystem with multidisciplinary skill sets and technology expertise. The complete paper discusses the challenges that face the development of such tubulars starting from academia and research institutes to complement expertise and computer computational power and moving through to material suppliers and manufacturing facilities for pipe prototyping.\u0000 \u0000 \u0000 \u0000 NM pipes also can include metallic elements, where a hybrid system of NM layers is incorporated into multilayered pipe structures that assume specific roles, similar to a metallic pressure armor layer in subsea flexible risers, jumpers, and flowlines. Another example is polymer-lined steel rigid pipes with glass-fiber reinforced epoxy (GRE), or a dual-layer thermoplastic-lined reinforced pipe (Fig. 1).\u0000 Composite-based NM pipes can broadly be categorized into reinforced thermoplastic pipe (RTP) and reinforced thermoset pipe (RTR), with glass-fiber reinforced plastic pipe (GRP) and GRE considered a subset of RTR. RTP consists of thermoplastic matrices and layers that can soften after heating and can harden when cooled in a reversible process, thus having the potential to recycle. Because of the flexibility of thermoplastic polymer, RTP pipes up to hundreds of meters long can be spooled on reels and deployed through rigless operation, with reduced system cost and deployment time. This synopsis will concentrate, as does the complete paper, on RTP.\u0000 RTP pipe design can be classified as unbonded, semibonded, or fully bonded. Essentially, three layers of constituents for RTP exist: the inner layer is a fluid barrier (liner), the second layer is a load-bearing component (reinforcement), and the outer layer is external protection (cover). Unbonded RTP pipe means that the layers are not heat-fused to one another during manufacturing and are free to move between layers. This type of RTP pipe usually is low to medium in pressure rating, especially with regard to collapse rating, but also is lower in manufacturing cost and is suitable in onshore applications for fluid transportation. To increase the pressure rating, semibonded RTP pipes can be considered if pipe thickness is a limitation. For offshore and downhole applications, however, where higher pressure and temperature ratings are required, fully bonded RTP pipes, more commonly known as thermoplastic composite pipes, are preferred to han","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141715250","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":"Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait","authors":"C. Carpenter","doi":"10.2118/0724-0096-jpt","DOIUrl":"https://doi.org/10.2118/0724-0096-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference.\u0000 \u0000 \u0000 \u0000 The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates.\u0000 \u0000 \u0000 \u0000 To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field.\u0000 \u0000 \u0000 \u0000 West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation.\u0000 The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API).\u0000 Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best.\u0000 North Kuwait (NK) Business Case.\u0000 The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes.\u0000 The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141695687","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 Conducts Mechanical Evaluation of Nonmetallic Tubulars","authors":"C. Carpenter","doi":"10.2118/0724-0085-jpt","DOIUrl":"https://doi.org/10.2118/0724-0085-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214488, “Mechanical Evaluation and Intervention in Nonmetallic Tubulars Using Current Technologies,” by Mohamed Larbi Zeghlache, SPE, and Khaled Al-Muhammadi, Saudi Aramco, and Iqbal Pervaiz, SPE, Baker Hughes, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 With increasing interest in nonmetallic products, such as fiberglass tubing, for downhole applications, ensuring well integrity in a similar way as is achieved for standard carbon steel completions is essential. One important aspect of well integrity is the ability to routinely access the downhole condition of the tubing and perform basic interventions. The complete paper demonstrates testing and validation of different mechanical evaluations of the integrity of fiberglass tubing using logging and intervention tools.\u0000 \u0000 \u0000 \u0000 Fiber-reinforced polymer composites have been used efficiently for various structural applications, including primary structures for which safety is a major design requirement. Fiber-reinforced laminate is very sensitive to out-of-plane loading, however, because it exhibits relatively low transverse properties. The resulting impact damage in fiber-reinforced polymer composite usually reduces its postimpact mechanical properties. The damage phenomenology in fiber-reinforced polymer composites involves many different mechanisms of degradation. Contrary to metallic materials, fiber-reinforced polymer composites can experience damage evolution followed by a catastrophic failure without prior notice. The inspection and monitoring of such damage during a structure’s lifetime are very challenging. Moreover, classical nondestructive testing techniques are difficult to implement for real-time structural health monitoring (SHM). It is, therefore, important to develop a reliable SHM technique that can both increase safety and reduce operational costs by optimizing inspection and repair.\u0000 \u0000 \u0000 \u0000 Of common barrier-inspection technologies, cement evaluation using sonic and ultrasonic measurements is very challenging across coated or nonmetallic casing. In the case of nonmetallic pipes such as fiberglass and composite pipes, this measurement is yet to be investigated for proper transducer design and signal processing. Magnetic and electromagnetic technologies cannot be used for casing inspection because the pipe material is an insulator and prevents any current flow. The simplest and most straightforward technologies remaining are mechanical tools for inner wall inspection. For this reason, testing was conducted to evaluate the effectiveness of multifinger caliper (MFC) logging in fiberglass casing and to simulate intervention operation through puncher and cutter services.\u0000 \u0000 \u0000 \u0000 An MFC is a mechanical tool that provides, through its fingers, high-resolution accurate radial measurements of internal diameter of tubing or casing string. MFCs are used to detect very small changes to the i","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699229","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":"Physics-Informed Machine Learning Applied to Complex Compositional Model in a Giant Field","authors":"C. Carpenter","doi":"10.2118/0724-0068-jpt","DOIUrl":"https://doi.org/10.2118/0724-0068-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23730,“Physics-Informed Machine-Learning Application to Complex Compositional Model in a Giant Field,” by Guido Bascialla, SPE, ADNOC, and Coriolan Rat and Soham Sheth, SLB, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 Compositional reservoir simulation is a time-intensive activity demanding complex physics. In the complete paper, the authors review the advantages of machine learning (ML) in complex compositional reservoir simulations to determine fluid properties such as critical temperature and saturation pressure. An ML approach to predict critical temperatures during simulation based on the Heidemann-Khalil method is implemented, resulting in more-accurate results with lower computational cost, outperforming the standard method and improving performance on a giant field model with compositional gradient and miscible gas injection.\u0000 \u0000 \u0000 \u0000 The case study refers to a giant offshore carbonate field composed of multiple reservoirs. Production is currently in a rampup phase; crestal miscible hydrocarbon gas injection was implemented soon after startup. The availability of high-potential gas producers as a source of makeup gas and the placement of peripheral water injectors maintains the reservoir pressure above minimum miscibility pressure. All reservoirs show complex variable slope compositional gradients along thick oil columns of hundreds of feet (Fig. 1). To match the fluid behavior and the variation of fluid properties with depth, the equation of state needs at least nine components.\u0000 The rock quality mainly is controlled by diagenesis. Thirteen rock types were modeled. The permeability can change up to four log cycles for the same porosity. Most of the reservoirs are highly heterogeneous, with features such as high-permeability streaks and baffle zones. A wide range of capillary pressure curves is present; these mainly depend on permeability and lithology.\u0000 Most development wells were completed with inflow control devices (ICDs) to control gas and water breakthroughs and optimize oil production. The combination of numerous ICDs and long slanted production intervals (i.e., thousands of feet) make wellbore-reservoir coupling critical for proper history matching and forecasting. The model grid size in the horizontal direction is 328 ft, which is considered optimal according to simulated sensitivities. The vertical layering is very fine in order to capture the reservoir heterogeneity; the cell thickness ranges from 1 to 1.5 ft. This results in a model with 3.5 million active cells, which makes the simulation performance and run time very challenging when coupled with compositional gradient and ICDs.\u0000 \u0000 \u0000 \u0000 In this section of the complete paper, the authors review why accurate phase labeling is important in compositional simulation and how it can lead to convergence problems, par","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141707434","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}