Artykuły w czasopismach: „Carpenter Company”

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Baird, Jane E. "Financial Reporting And Tax Issues At JC Construction Corporation: An Instructional Case". Journal of Business Case Studies (JBCS) 4, nr 3 (27.06.2011): 9. http://dx.doi.org/10.19030/jbcs.v4i3.4762.

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JC Construction Corporation (JCCC) is a privately held corporation with 10 shareholders, who are all members of the Carpenter family. The company was founded by Joe Carpenter in the late 1990s. The companys projects involve mostly comparatively small commercial building construction, such as restaurants and smaller-scale stores. JCCC specializes in renovation and restoration projects rather than new construction, but does occasionally take on some new construction projects. The company does not build or renovate single family homes. JCCC is located in Minnesota, near the Minneapolis/St. Paul area where remodeling contractors are in high demand.

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Simões, Mariana Roberta Lopes, Adelaide De Mattia Rocha i Carla Souza. "Factors associated with absenteeism-illness in rural workers in a timber company". Revista Latino-Americana de Enfermagem 20, nr 4 (sierpień 2012): 718–26. http://dx.doi.org/10.1590/s0104-11692012000400012.

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The monitoring of absenteeism-illness has revealed its high prevalence, and a strong relationship with work. This study aimed to analyze the factors associated with absenteeism-illness among the rural workers in a timber company in Minas Gerais, Brazil. It is an analytical cross-sectional study, carried out among 883 workers. The medical certificates issued in the company over one year were surveyed. For the analysis, use was made of descriptive statistics and bi- and multivariable analyses. The strength of association was measured by the odds ratio (OR) with help from logistic regression (p<0.05). A prevalence of 54% of medical certificates was found in the population. Bivariate analysis revealed an association between job (forestry assistant (OR=13.1), carpenter (OR=15) and chainsaw operator (OR=39.6)), length of service in the company, departments and length of schooling with absenteeism-illness. In the multi-variate analysis, the association between length of schooling and being a carpenter disappeared, while the other associations remained. It is concluded that there is important evidence about the occupational and demographic factors and absenteeism-illness among forestry workers.

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Humphris, Adrian, i Geoff Mew. "Carpenter, Artisan, Architect; Status In Late Nineteenth Century Wellington". Architectural History Aotearoa 4 (31.10.2007): 28–33. http://dx.doi.org/10.26686/aha.v4i0.6737.

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The distinction between a minor professional architect and a leading builder in Wellington was considerably more blurred in the late nineteenth century than it would be today. However, busy architects could make a lot of money and the term "architect" carried status that might open more doors than would be available to a mere builder. Late nineteenth century Wellington is now apparently only represented by a handful of buildings by prominent architects. Most people automatically think of the CBD and names like Thomas Turnbull & Son, William Chatfield, Frederick de Jersey Clere, John Campbell and perhaps William Crichton. Clayton, Toxward and Tringham were dead or almost gone, and new generation architects were barely emerging. We contend, however, that this picture is an oversimplification and considerably more of 1890s Wellington remains, as does the evidence for a much longer roll-call of architects, some of whom practised on the fringes, both of the city and of their profession. The architects we discuss here did not generally design large, flamboyant buildings, nor did they cater for rich company clients. Many of the lesser-known architects were particularly susceptible to boom-bust cycles and were forced to seek other employment in lean times - hence their rapid arrivals and departures from the trade listings in the directories of these years

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Youabd, Saadia, Loubna Tahri, Kamal Wifaq, Asmaa Omali i Abdeljalil El Kholti. "O-215 POST-MORTEM RECOGNITION OF NASOPHARYNGEAL CANCER AS AN OCCUPATIONAL DISEASE IN A CARPENTER". Occupational Medicine 74, Supplement_1 (1.07.2024): 0. http://dx.doi.org/10.1093/occmed/kqae023.1012.

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Abstract Introduction Post-mortem recognition of occupational diseases is a crucial step aimed at establishing a link between a disease contracted by an individual and their work environment. It is essential for safeguarding the rights of the deceased and their family. The objective of the presented case study is to examine the post-mortem recognition of nasopharyngeal cancer in a carpenter, linked to their occupational exposure to formaldehyde. Materials and Methods Tripartite medical expertise was conducted by the occupational health service at Ibn Rochd University Hospital, following a request from the Casablanca court of first instance. Results The plaintiff, aged 51, worked as a carpenter for seven years in a company engaged in wood treatment and furniture design. Their exposure to wood dust and formaldehyde was reasonably considered to be the cause of nasopharyngeal cancer, resulting in a permanent physical disability of 70%. After the worker’s death, an evaluation of compensation for their beneficiaries was conducted. Discussion Formaldehyde has been classified as a human carcinogen by the International Agency for Research on Cancer in 2004. The causal relationship between the activity of varnishing wooden furniture and nasopharyngeal cancer is firmly established and is listed in the Moroccan Table of compensable occupational diseases, No. 1.2.8bis. Conclusion Compensation for the beneficiaries is essential to support families of workers who have died from occupational diseases. However, implementing preventive measures in the workplace is equally critical to protect the health of workers and prevent such cases in the future.

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van den Bersselaar, Dmitri. "“Doorway to Success?”: Reconstructing African Careers in European Business from Company House Magazines and Oral History Interviews". History in Africa 38 (2011): 257–94. http://dx.doi.org/10.1353/hia.2011.0012.

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The largely literate African employees of European businesses during the colonial and postcolonial period have not been studied as a group, unlike miners, railway workers and colonial intermediaries. This group has nevertheless been of great importance. Many of its members became part of the core of the management of African-owned enterprises and organizations, others started their own businesses or became successful politicians. African employees of European business, alongside government employees, formed the basis of the rapidly growing middle classes during the period after the Second World War. They gave their children a Western-style education, often at well-respected schools. In many local communities the “manager” became a figure of respect. Many employees were elected to traditional office as chiefs. Such successes were not limited to those employees who made it into management. For example, a carpenter with a steady career with a European company could build and own several houses. These African employees domesticated capitalism in West Africa, mediated changes in consumption and the rise of a consumer society, and adopted European expectations of career progression and life cycle. Working for a European business, they also found themselves at important sites of contestation during colonial and postcolonial political struggles.

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Petrakos, Christopher. "The ‘spiritual borderlands’ of the far Canadian north: the ministries of William Carpenter Bompas and Robert McDonald in comparative context". British Journal of Canadian Studies 35, nr 2 (wrzesień 2023): 139–64. http://dx.doi.org/10.3828/bjcs.2023.9.

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Anglican Bishop William Carpenter Bompas and Archdeacon Robert McDonald spent nearly forty years in the far American north ‘spreading the word’ to Indigenous peoples living along the Yukon River in the second half of the nineteenth century. This article investigates their work primarily among the Gwichyà Gwich’in from their arrival in the 1860s to the mid-1870s when the 141st meridian west was established, creating an international border between Alaska and the Yukon, the United States and British America. The border’s creation had enormous implications for the Hudson Bay Company at Fort Yukon (Gwichyaa Zheh) because it was discovered to be west of the international boundary in Alaska and was moved further east into today’s Yukon Territories. The border forced Indigenous people to pick a side, American or British, and tested loyalties to their minister. The ‘spiritual borderland’ thus offers a window into the lives and ministries of two important northern missionaries during the initial contact period, as well as assessing their successes and failures among northern peoples.

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Carpenter, Chris. "3D Geological Model Creates Potential for Increased Production in Libyan Field". Journal of Petroleum Technology 73, nr 08 (1.08.2021): 44–45. http://dx.doi.org/10.2118/0821-0044-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201417, “Reservoir Characterization and Geostatistical Model of the Cretaceous and Cambrian-Ordovician Reservoir Intervals, Meghil Field, Sirte Basin, Libya,” by Mohamed Masoud, Sirte Oil Company; W. Scott Meddaugh, SPE, Midwestern State University; and Masud Eljaroshi Masud, Sirte Oil Company, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The study outlined in the complete paper focuses on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The objective of this study is to develop a representative geostatistically based 3D model that preserves geological elements and eliminates uncertainty of reservoir properties and volumetric estimates. This study demonstrates the potential for significant additional hydrocarbon production from the Meghil field and the effect of heterogeneity on well placement and spacing. Introduction The reservoir of interest consists of three stratigraphic layers of different ages: the Waha and Bahi Formations and the Gargaf Group intersecting the Meghil field. The Waha reservoir is a porous limestone that forms a single reservoir with underlying Upper Cretaceous Bahi sandstone and Cambro-Ordovician Gargaf Group quartzitic sandstone. The Waha provides excel-lent reservoir characteristics. The Bahi has fair to good reservoir characteristics, while the Gargaf Group has very poor reservoir quality. The Waha and Bahi contain significant amounts of hydrocarbons. The Bahi is composed of erratically distributed detritus from the eroded Gargaf Group. The characteristic of the Gargaf sediments is quartzitic sandstones indurate to a quartzite with low reservoir quality.

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Carpenter, Chris. "Benchmarking Study Finds Additional Potential of Ultimate Recovery Factor Across Kuwait". Journal of Petroleum Technology 73, nr 12 (1.12.2021): 33–34. http://dx.doi.org/10.2118/1221-0033-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203422, “Benchmarking of Ultimate Recovery Factor Across Kuwait: Unlocking Additional Potential,” by Mohammad Al-Ghanemi, Prashant Dhote, SPE, and Anup Bora, Kuwait Oil Company, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. A countrywide benchmarking of ultimate recovery factor (URF) for oil reservoirs in Kuwait is presented in the complete paper. The results of this study have been useful in supporting identification of long-term opportunities for the operator and have influenced the creation of conceptual development plans for newly discovered prospects. The study focused on the reservoir complexity index (RCI) method and global analogs to identify development opportunities and improvements to the URF in the brown and green fields of Kuwait. Approach to Reservoir Benchmarking The recovery factor of a reservoir is a function of reservoir characteristics such as structural compartmentalization, depositional continuity, reservoir net-to-gross, permeability, fluid type, pressure, and field-development choices such as recovery process, well-completion type, and well spacing. Therefore, to benchmark reservoir performance appropriately, it is important to consider those factors relevant to the reservoir being studied. Additionally, limited value exists in using an analog with the “correct” reservoir geology and fluid properties if the development scheme is not also considered. The study provides an objective procedure to measure the uncertainty in reservoir complexity and characterization. It also identifies and documents appropriate analog data derived from internal company and commercial third-party databases. Selection of Analog Reservoirs - The process for gathering appropriate analog reservoirs does not seek to identify a single perfect analog. Instead, it aims to analyze key reservoir characteristics and field-development methods to identify groups of analogs, which in aggregate can represent a reasonable comparison with a study reservoir. The philosophy is to select a range of analog reservoirs based on the key parameters that influence URF.

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Krusekopf, Charles, Alice de Koning i Rebecca Frances Wilson-Mah. "From start-up to expansion: Vittrium Building Products". CASE Journal 14, nr 6 (12.11.2018): 672–93. http://dx.doi.org/10.1108/tcj-12-2017-0112.

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Synopsis After three years in business together, Des Carpenter and Kees Schaddelee had a decision to make – should they double the size of their location, based on the opportunities and competitive threats they perceived? The startup phase took longer than expected and access to distribution channels was more difficult than expected. Nonetheless, the business gained traction with online sales that proved the concept of custom-made counters using EnvironiteTM technology was viable. As they prepared to expand the business, the owner-managers needed to decide on a growth strategy that would let them leverage their strengths. In analyzing their successes so far, they needed to evaluate their business model including their product line, target markets, marketing strategy (including the pricing strategy, product lines, and channels of distribution) and operations. Research methodology Data were collected through interviews with business owners and a review of company documents, production processes and the company website. Relevant courses and levels This case exercise will suit strategy and entrepreneurship students at both the senior undergraduate level and graduate level. The case discussion will ask students to consider operations, supply chain management, marketing and other issues, all through the lens of a holistic vision for the company. This case may be taught as an example of a growth strategy or a business model in a capstone business strategy course or higher level entrepreneurship course. It is appropriate for both undergraduate seniors and graduate students. Theoretical bases This case may be taught as an example of a growth strategy or a business model in a capstone business strategy course or higher-level entrepreneurship course. The case may be used to help students understand external and internal analysis, identifying the sources of value creation and competitive advantage, and creating an appropriate strategy for growth. It provides a rich context to discuss and apply the following conceptual tools: the application of a value chain analysis and the application of a business model canvas (key partners, key activities, key resources, value propositions, customer relationships, distribution channels, customer segments, cost structure and revenue streams). The case may also be used to reinforce the applications of growth phases in a young firm that are part of the entrepreneurial setting, for example, value proposition, ideal customer, revenue streams and key performance indicators.

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Carpenter, Chris. "Study Reviews Recent Polymerflooding Advances in China". Journal of Petroleum Technology 74, nr 06 (1.06.2022): 90–93. http://dx.doi.org/10.2118/0622-0090-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200084, “Recent Advances of Polymerflooding in China,” by Hu Guo and Kaoping Song, China University of Petroleum, and Yuming Wang, Daqing Oilfield Company, et al. The paper has not been peer reviewed. Polymerflooding is one of the more promising chemical enhanced oil recovery (EOR) techniques that features high incremental oil recovery factor, low cost, and wide reservoir applicability. This paper helps clarify ideas regarding polymerflooding implementation based on theory and practice in China. Introduction Laboratory studies aimed at increasing understanding of polymerflooding involve criteria for matching polymer with porous media, the polymer viscoelasticity effect on residual oil saturation (ROS), and displacement efficiency and synthesis of new polymers with better viscosifying capacity compared with typical partially hydrolyzed polyacrylamide (HPAM). The plugging of injectors in many oil fields is becoming increasingly common in many commercial blocks. This problem is especially serious for high-concentration polymer-injection blocks in fields such as Daqing, Xinjiang, and Henan. Understanding this phenomenon involves aligning the polymer and porous-media parameters such as permeability and pore size. Actual reservoir pressure distribution also must be considered. Because modern chemical EOR is based on ultralow interfacial tension (IFT) and minimum mobility ratio theory, the idea of combining the benefits of reducing IFT and increasing displacing-phase viscosity leads to a synthesis of amphiphilic polymers, which have features of both polymers and surfactants. This new type of polymer is sometimes called polymeric surfactant in China.

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Carpenter, Chris. "Project Tool Allows for Continuous Improvements to Business Processes". Journal of Petroleum Technology 74, nr 12 (1.12.2022): 44–46. http://dx.doi.org/10.2118/1222-0044-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205603, “Reserves and Resources Management: A Continuous Improvement of the Business Processes,” by Aen Nuril Hadi, Stephen Leonardo, and Khairul Anwar, Pertamina, et al. The paper has not been peer reviewed. _ To obtain standardized reserves and resources management of geographically diverse assets, Pertamina has launched a company guideline influenced by the SPE Petroleum Resources Management System (PRMS). A tool called the Project Box enables reserves analysts to map all projects, evaluate portfolios, and monitor progress of the project in the development and exploration phases. Furthermore, in line with a digitalization campaign, the Project Box, all reserves and resources data, and other strategic information are stored and maintained by in‑house software. Introduction As an Indonesian state‑owned energy company, Pertamina has managed more than 800 structures in Indonesia and overseas. In terms of structures, most of the company’s assets are associated with two islands, Sumatra and Java, which collectively contribute more than 75% of these assets. However, in terms of petroleum initial in place (PIIP), the island of Kalimantan is more significant. In terms of operatorship, assets that are scattered throughout the region are managed differently. More than 80% of these assets are operated by the company, while the rest is operated by other companies in the form of participating-interest division and unitization. From 2011 to 2020, because of merger and acquisition activities, the PIIP value continuously increased. In 2018, the acquisition of the Mahakam block led to an addition to PIIP of almost 50%. Subsurface-Asset Performance Heterogeneity Several key performance parameters are used to evaluate the reserves and resource performance of all structures managed by the company. These parameters include the following: - Reserves to production (RTP) indicates the reserves life span of a field or structure in years with the latest annual production. An abnormally high RTP may indicate either that the field or structure is just being put into production or that the reserves are subject to reevaluation. - Maturity is related to project maturity relative to current cumulative production. A maturity close to 100% means that almost all projects are matured into production and nearly approaching end life of the structure or field. - Withdrawal rate indicates the latest annual production performance relative to reserves. A low withdrawal rate may indicate either a petroleum-recovery optimization opportunity or that the reserves are subject to reevaluation. - Reserves replacement ratio (RRR) indicates the annual additional reserves 1P relative to annual production. An RRR equivalent to 100% means that the additional reserves—namely, projects maturing through final investment decision (FID) approval—can make up the produced volume of petroleum in the respective year. - Ultimate recovery factor (RF) indicates the expected recovery of a field or structure through the entire development process. While ultimate RF may seem to be greatly affected by subsurface aspects, it also can be improved through technology breakthroughs.

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Kirkpatrick, Melissa. "Earthen Vessels: American Evangelicals and Foreign Missions, 1880–1980. Edited by Joel A. Carpenter and Wilbert R. Shenk. Grand Rapids, Mich.: William B. Eerdmans Publishing Company, 1990. xvii + 350 pp. $15.95." Church History 63, nr 2 (czerwiec 1994): 320–21. http://dx.doi.org/10.2307/3168642.

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Carpenter, Chris. "Modeling, Planning Allow Successful Implementation of South Texas U-Turn Lateral". Journal of Petroleum Technology 74, nr 05 (1.05.2022): 88–90. http://dx.doi.org/10.2118/0522-0088-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208801, “Successful Planning and Implementation of First South Texas U-Turn Lateral,” by Riley Schultz and Joe Kiefner, Chesapeake Energy. The paper has not been peer reviewed. Legacy fields require innovative solutions for developing capitally efficient projects within highly developed acreage blocks. As another tool to improve well economics, a U-turn lateral strategy was implemented in the Eagle Ford Shale. This wellbore trajectory resulted in capturing a 9,200-ft equivalent lateral length well in a 5,000-ft-wide lease space. This successful U-turn trajectory test has created new economic project opportunities for the company and has increased optionality within challenged lease spaces across the field. Well Overview In a single U-turn well, the horizontal wellbore turns 180° to create two parallel laterals in a map-view U shape. The successful U-turn project detailed in the complete paper was the first drilled in south Texas (Fig. 1). This resulted in significantly improved economics by using a horizontal turn as a hydrocarbon pathway, rather than an additional vertical section from a new well to gain the equivalent treatable lateral length. This well followed operator standards for south Texas Eagle Ford two-casing-string well design. A 9⅝-in. casing was set to protect shallow water zones, and an 8¾-in. production section was drilled for the remainder of the well (using 5½-in. drillpipe). 5½-in. production casing was then run to total depth (TD). 8¼-in. centralizers were placed on each joint of the casing, freely floating between the collars. The production section was drilled with oil-based mud, and a standard cement job was pumped. Conventional directional tools were used for the entirety of the drilling phase. The decision was made early in the planning phase of the well to forgo fracturing the turn portion of the wellbore and instead drill into the adjacent unit to conduct the turn to maximize the amount of optimally oriented lateral footage in the unit to be produced.

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Carpenter, Chris. "Multidisciplinary Integrated Approach Unlocks Fracture-Characterization Ambiguity". Journal of Petroleum Technology 75, nr 08 (1.08.2023): 40–42. http://dx.doi.org/10.2118/0823-0040-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213771, “Unlocking Fracture-Characterization Ambiguity: A Multidisciplinary Integrated Approach,” by Ali Abughneej, Mohamed Al-Naqeeb, and Mohammed Al-Ostath, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. _ Fracture systems play a significant role in production in the case of tight, low-porosity complex reservoirs. An exploration well in North Kuwait that targeted the Middle Marrat formation encountered uncertainty regarding reservoir compartments in an underexplored field, with minimal offset wells to properly evaluate its potential. A multidomain approach is proposed leveraging different types of expertise to tackle the petrophysical and geomechanical aspects of the fracture system governing the carbonate layer and assess its producibility and qualification for stimulation through hydraulic fracturing. Introduction A comprehensive study was performed on Well A targeting the Marrat formation, a tight, low-permeability carbonate Jurassic reservoir. During the last two decades, the operator has drilled many vertical and deviated wells through this formation. Hydrocarbon production from the closely spaced wells shows a major variation in flow rates, which has been attributed to the presence of uncharacterized fracture clusters as well as the limited understanding of reservoir compartmentalization. To address the challenges of production discrepancy, an innovative multidomain approach was proposed as an integrated solution in an attempt to understand the fracture systems governing the reservoir setting and its compartments and further assess their connectivity and extent to form a perspective on their possible contribution or hindrance to flow. An end-to-end comprehensive work flow was created combining the results of advanced formation evaluation, high-resolution borehole imaging, and state-of-the-art sonic imaging [the 3D far-field sonic (3DFFS) approach], followed by a fracture-stability analysis for the purposes of completion optimization and potential future hydraulic fracture design. Geological Setting Middle Marrat is targeted as the hydrocarbon-bearing zone, consisting of dolomitized oolitic grainstone to packstone facies, reflecting the high-energy inner-midramp shoal depositional environment.

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Perko, F. Michael. "Making Higher Education Christian: The History of and Mission of Evangelical Colleges in America. Edited by Joel A. Carpenter and Kenneth W. Shipps. Grand Rapids, Michigan: William B. Eerdmans Publishing Company, 1987. xvi + 304 pp. $16.95." Church History 58, nr 3 (wrzesień 1989): 413–14. http://dx.doi.org/10.2307/3168509.

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Carpenter, Chris. "Case Study Details Reserves and Resource Management During a Merger". Journal of Petroleum Technology 73, nr 12 (1.12.2021): 37–38. http://dx.doi.org/10.2118/1221-0037-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206322, “Business-Oriented Reserves and Resource Management: Experiences From a Merger,” by Thies Dose, SPE, and Gunar Kachel, Wintershall Dea, prepared for the 2021 SPE Annual Technical Conference and Exhibition, Dubai, 21–23 September. The paper has not been peer reviewed. In May 2019, the merger between Wintershall and DEA Deutsche Erdoel was closed, which was the birth of Wintershall Dea (WD). A system for internal reporting of petroleum resources described in the paper provides a fit-for-purpose approach, such as a consistent interpretation of commerciality criteria or definition of resources subclasses. A systematic resource-control system is defined, focusing on internal review, external and internal audits, and synergetic use of project reviews. Merging Existing Resource Reporting Legacy Wintershall reported resources both according to the Petroleum Resources Management System (PRMS) and the Securities Exchange Commission. PRMS reserves subclasses were reported according to project maturity (i.e., On Production, Approved for Development, and Justified for Development). This classification illustrates the project status of assets within the portfolio. The conversion factor from gas to oil equivalent was 5,600 scf/BOE, accounting for a high fraction of caloric gas in the portfolio. The official reserves and resource reporting of the legacy company toward its stakeholders was based on internally estimated reserves and resources figures. This was backed up by regular external reserves and selected contingent resources (CR) audits for control and calibration of the reported numbers. Legacy DEA reported resources according to PRMS only. Reserves subclassification was based on reserves status (i.e., Developed Producing, Developed Nonproducing, and Undeveloped). This highlighted the differentiation according to operational and funding status (Fig. 1). DEA’s reserves reporting was directly taken from external reserve audits, whereas CR were compiled from internal estimates. Because the portfolios of both legacy companies were mixed with respect to petroleum products, results needed to be normalized based on BOE. For the sake of consistency, all gas resources from legacy DEA were reconverted to oil-equivalent standards of legacy Wintershall. To lay groundwork for the respective filing of documents, various 1P and 2P reserves information from audits executed by the legacy companies had to be aggregated to provide a reliable and consolidated database for investors.

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Carpenter, Chris. "Caspian Experience Boosts Performance in Turkey’s Onshore UGS Project". Journal of Petroleum Technology 75, nr 10 (1.10.2023): 78–80. http://dx.doi.org/10.2118/1023-0078-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207011, “Healthy Caspian Experience Helps Boost Drilling Performance in Turkey’s Onshore UGS Project,” by Elchin Akbarli and Rufat Mammadbayli, SPE, SOCAR AQS. The paper has not been peer reviewed. _ In the complete paper, the authors describe an operator’s underground gas storage (UGS) project. The intent of the paper is to demonstrate the execution methodology and technologies that the company used to deliver the work on time and under budget. The authors outline planning, design, and drilling and completion strategies used during the execution phase. The authors add that the company’s experience in Caspian operations was of great benefit to the project. Introduction A plan was developed to expand a UGS facility in a salt cavern field. The main challenge of the project was the requirement to complete all wells within a short time frame with a limited budget while keeping the project economically feasible for the company without compromising safety and environmental protection. Geological risks and uncertainties required additional preliminary considerations, leading to a focus on the best methods available for the drilling and completion of 40 planned wells. A comprehensive cost analysis was performed to evaluate the approach. The operations were divided into three stages: tophole drilling, main drilling, and completion. Different types of rigs, with different capabilities depending upon the range of the work, were assigned for each phase. The plan involved three small truck-mounted mobile rigs to begin tophole drilling and run 30-in. conductor casings to isolate unconsolidated formations and freshwater zones. Then, six main rigs would be mobilized to perform the main stages of drilling; three completion rigs would finalize the project. The company’s Caspian experience applied to several technical aspects of the project, from optimization of drilling activities to planning and execution. The project presented many technical challenges, including geological hazards, deviation control, and strict requirements of well integrity for a long period of time. Rig Specifications for Drilling Stages A major decision point in the planning phase was to select different types of rigs to implement various drilling operations in a staged manner. Initially, 125-ton-capacity truck-mounted rigs began to drill 36-in. tophole sections and run 30-in. casings; then, the task was passed to main drilling rigs with installed 30-in. conductor casing. Top holes were drilled with three low-cost, low-capacity rigs to combat the high potential of lost-circulation problems that could be experienced with high-cost main drilling rigs. In the second stage, main drilling rigs with 225-ton and 300-ton capacity were involved for the next 26- and 17½-in. sections. In the third stage, low-capacity rigs were moved to the well locations to complete wells, either running the last leaching string of 10- and 7-in. casings or underreaming 12-in. to 17½-in. sections before running leaching strings.

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Carpenter, Chris. "Optimization Process Maximizes Financial, Environmental Benefits in LNG Breakwater". Journal of Petroleum Technology 73, nr 09 (1.09.2021): 55–56. http://dx.doi.org/10.2118/0921-0055-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31284, “Greater Tortue Ahmeyim Project for BP In Mauritania and Senegal: Breakwater Design and Local Content Optimizations,” by Alexis Replumaz, Yann Julien, and Damien Bellengier, Eiffage Génie Civil Marine, prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. During summer 2017, the authors’ company was invited by BP to bid for the construction of a concrete caisson breakwater protecting an offshore liquefied natural gas (LNG) floating terminal at a water depth of 33 m on the Mauritanian/Senegalese maritime border. As a result of subsequent front-end engineering design (FEED) studies, including 3D model testing, the company was able to reduce the amount of concrete required by 40% compared with the initial design, leading to financial and environmental benefits. Introduction The BP Tortue development comprises a subsea production system tied back to a pretreatment floating, production, storage, and offloading (FPSO) unit, which transfers gas to a near-shore hub for LNG production and export. Phase 1 will provide sales gas production and domestic supply and will generate approximately 2.5 mtpa of LNG to Mauritania and Senegal. The Phase 1 FPSO, in 100–130 m of water, will process inlet gas from the subsea wells located across several drill centers by separating condensate from the gas stream and exporting conditioned gas to a hub, where LNG processing and export will occur. The hub, 10 km from shore, comprises a breakwater to protect marine operations, including LNG processing and carrier loading. A single floating LNG vessel will condition the gas for LNG export. Hub construction began early in 2019 and should be completed in 2021 for a first-gas target in 2022. The breakwater design was conceived during the bidding stage of the project at the end of 2017 by proposing an alternative design for the breakwater adapted to project-specific conditions and regional facilities. The design has been improved continuously and optimized during the FEED stage based on a collaborative approach between the client and the contractor. Client Preliminary Design Optimizations During pre-FEED and bidding stages, the client performed an intensive geotechnical campaign based on several shallow and deep boreholes and a large-area geophysical survey. In water depths greater than 18 m along the maritime boundary between Mauritania and Senegal, a significant layer of soft soil exists, except around the outcrop located on the west side (10–11 km offshore in approximately 33 m of water). Although rock quantities could be slightly higher in the western location, the reduction of the dredging quantities and the reduction of the effect on the nearby coastal community of Saint Louis (lighting, noise, and vessel traffic) led to selection of this location for the hub terminal. The initial breakwater type was a rubble-mound structure. However, a composite breakwater (caisson on berm foundation) allowed for optimization of dredging and rock quantities. The change in breakwater type allowed a rock-quantity drop from 5.8 million to 1.1 million m3.

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Carpenter, Chris. "Adaptive Framework Aims To Develop Resilient Supply Chain Using 3D Printing". Journal of Petroleum Technology 73, nr 12 (1.12.2021): 44–45. http://dx.doi.org/10.2118/1221-0044-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203089, “Adaptive Framework for Resilient Supply Chain Using 3D Printing in the Oil and Gas Industry,” by Yousef Al Tartoor, Adel Khalaf, and Mohammed Awadallah, ADNOC, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Resilient supply-chain management plays an essential role in organizational success. While an effective supply chain is dependent on logistics, inventory control, and materials handling, it is also strongly interlinked with the use of new technologies that will enhance the complete supply-chain cycle. The complete paper develops a framework that introduces 3D printing in the oil and gas industry, taking into consideration the challenges that this technology is facing to penetrate a generally conservative industry and realizing its potential benefits. Sourcing Materials Challenges (As-Is Situation) Additive manufacturing can play a vital role in resolving pains experienced by global aftermarket supply chains. It can help in dealing with obsolescence of materials after the end of service, when the materials are either not available in market, very costly, or missing technical drawings and data sheets. Also, high uncertainty in the planning of demand in oil and gas leads to reordering of unnecessary materials because of high order quantity minimums or having the required parts as a part of kits (usually other items in such kits are nonmoving). Another supply-chain issue is long lead times for purchasing materials, especially internationally. Moreover, additive manufacturing can be a cost-effective solution with less material waste, especially for precious materials. Finally, additive manufacturing can help relieve the problem of working capital being locked up in inventory as a result of accumulation of dead inventory (nonmoving items), leading to scrapping or write-off of unused spare parts. Fig. 1 compares the cost of traditional methods of reverse engineering with 3D printing. Conventional methods of reverse engineering, such as casting or forging, can be cost-effective for noncomplicated configurations. As the complexity of the part increases, however, the cost increases exponentially, revealing 3D printing as the more cost-effective approach. Several commodities in the oil and gas industry can be plotted beyond the breakeven point in the figure. Such materials include 2D and 3D impellers, various valves, control-valve plugs and diffusers, casing scrapers, fuel injectors, nozzles, vanes, and blades. Market Analysis and Self-Assessment Political, economic, sociological, technological, legal, and environmental (PESTLE) analysis of their operating company was performed by the authors to gain a better understanding of the current situation of the business and external environment factors that may affect the company’s activities without much direct control from the company. From the standpoint of PESTLE analysis, the technological factor seems to be promising, considering reverse engineering and 3D printing of materials on demand. If any certified local workshop or 3D printing facility is able to produce like-original-equipment-manufacturers’ (OEM) spares, then certificates of conformity and warranty should be provided that match OEM warranties (generally 12 months from installation or 18 months from receiving the materials, whichever comes first).

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Badir, Patricia. "Meg Twycross and Sarah Carpenter. Masks and Masking in Medieval and Early Tudor England. (Studies in Performance and Early Modern Drama.) Aldershot and Burlington, VT: Ashgate Publishing Company, 2002. x + 418 pp. index. illus. bibl. $84.95. ISBN: 0-7546-0230-3." Renaissance Quarterly 56, nr 4 (2003): 1316–17. http://dx.doi.org/10.2307/1262080.

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Carpenter, Chris. "Study Describes Challenges, Opportunities of CO2 EOR in China". Journal of Petroleum Technology 74, nr 07 (1.07.2022): 87–89. http://dx.doi.org/10.2118/0722-0087-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209468, “CCUS In China: Challenges and Opportunities,” by Hu Guo, China University of Petroleum; Xiuqin Lyu, Sinopac Northwest Oil Field Company; and En Meng, China University of Petroleum, et al. The paper has not been peer reviewed. One of the most attractive carbon capture, usage, and storage (CCUS) applications in China is that of carbon dioxide (CO2) enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 presents an important path for China. The complete paper reviews the progress of CCUS technology in China. The current challenges of CCS EOR include high capture costs, small scale, low incremental oil recovery, and huge capital input. The costs can be significantly reduced when the scale is enlarged to the commercial level and transportation costs are further reduced by pipelines or trains. Importance of CCUS At the time of writing, 49 CCUS pilots or field tests had been conducted or were under construction in China. CCUS demonstration projects were small-scale, and no projects involving more than 1.0 million tons of CO2 per year (mtpa) were conducted. 1.3 million tons of CO2 were estimated to be injected in 2020 for EOR use. The authors reference a study that mentions nine CO2 EOR projects. Among these, the Jilin oilfield project was notable for its size of 2.0 million cumulative tons of CO2 injected. CO2-enhanced coalbed methane was also an attractive option for China, and several field tests were conducted by CNOOC and its partners. Another notable CCUS demonstration project involved the Shaanxi Jinjie power plant. This was the largest coal-fired power postcombustion (PC) CO2-capture project, with a capture capacity of 0.15 mtpa. The project began in November 2019. In January 2021, equipment installation was completed. By June of 2021, 168 trial operations had been passed. The captured CO2 will be used for EOR. This demonstration project will gain knowledge to reduce PC CO2 emissions, a great challenge for China because the majority of electricity is based on coal combustion. Gas processing and power plants rank first for the US in terms of CCUS project numbers. Power plants also rank first in the number of CCUS projects for China, but the number of natural-gas-processing projects was much less.

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Carpenter, Chris. "Collaboration Allows Introduction of Automated Advisory System in Offshore Well". Journal of Petroleum Technology 74, nr 10 (1.10.2022): 71–73. http://dx.doi.org/10.2118/1022-0071-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31443, “Operator and Service Provider Collaborate To Successfully Introduce an Automated Advisory System in a Wildcat Exploration Well Offshore Mexico,” by Peter Batruny, SPE, M. Razali Paimin, and M. Arriffuddin Allauddin, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ The authors of the complete paper describe a collaboration between an operator and a service company formed during a project’s well-planning phase to evaluate the feasibility of automation for a holistic drilling-advisory platform that facilitates real-time decision making based on downhole and surface data. The collaboration resulted in a successful deployment of an automation platform as a solution to manage and mitigate risks and optimize drilling operations in exploration wells. Introduction The probability of nonproductive time (NPT) and invisible lost time (ILT) occurring in exploration wells is higher because of a lack of experience in the area concerned. The operator estimates that NPT caused by hole problems accounts for 22% of total NPT (Fig. 1). The authors’ work aims to apply a novel, automated drilling-operation monitoring technique on a wildcat exploration well in the Gulf of Mexico through the collaboration of operator and service provider. A collaborative framework and technology integration is applied to minimize the effect of uncertainty on NPT and ILT. Description and Application of Equipment and Processes The well is in the Salina Basin, approximately 67 nautical miles north of shore, with an estimated water depth of 66 m below mean sea level. The maximum planned well total depth was approximately 4400 m true vertical depth subsea. The proposed well lies in a four-way anticline structure. Despite the abundance of wells around the location, most exploration activities performed in the area have been focused on the Middle and Lower Pliocene (shallower) interval, causing well correlation at the Miocene stratigraphic interval to be extremely limited. In addition, the disparate thicknesses of the Pliocene sediments in the area create significant challenges in terms of geological correlation. Five offset wells were used as stratigraphy correlation, with distances ranging from 8 to 31 km. Downhole losses and borehole instability were experienced in all offset wells, with well-control events experienced in three out of five offset wells.

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Carpenter, Chris. "Fiberglass-Lined Tubing Helps Prevent Asphaltene Deposition in Oil Wells". Journal of Petroleum Technology 73, nr 07 (1.07.2021): 55–56. http://dx.doi.org/10.2118/0721-0055-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21441, “First-Time Worldwide Application of Glass-Reinforced Epoxy-Lined Tubing for Prevention of Asphaltene Deposition in Tubing in Oil Wells: A Case Study From Kuwait,” by Reji E. Chinnappan, SPE, Milan Telang, SPE, and Riyad Quttainah, SPE, Kuwait Oil Company, et al., prepared for presentation at the virtual 2021 International Petroleum Technology Conference, 23 March–1 April. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. Asphaltene deposition in production tubing represents a major flow-assurance challenge. Common strategies to mitigate asphaltene deposition downhole include mechanical or solvent cleanouts and chemical inhibition. These are associated with production deferment, high job costs, safety and environmental risks, and operational issues. An operator has addressed this challenge using production tubing lined with glass-fiber-reinforced epoxy (GRE). This technology was implemented in two trial wells. The paper describes the different mitigation strategies employed by the operator and presents the findings of successful trials. Background Jurassic wells of a Kuwait Oil Company asset are producing light crude from a tight matrix-type reservoir located at a depth of 13,000–15,000 ft. Reservoir pressure has depleted from approximately 9,500–10,000 psi to approximately 6,000 psi because of sustained production in the absence of any significant pressure support. Oil production rates per well have diminished to the 500- to 1,000-BOPD range. The oil features high asphaltene onset pressures (4,000–5,000 psi). When considering time-lapse plots of caliper logs from a well where asphaltene deposition used to occur, the plot indicates that significant asphaltene deposition in the well took place below 4,500 ft and progressively increased over time. In approximately 5 months, the average internal diameter of the tubing reduced from 2.75 in. to less than 2 in., thereby constricting the flow significantly and requiring cleaning of the tubing. In extreme cases, the tubing string could be fully plugged. Many field trials with different tools and chemicals using batch and continuous treatment have been conducted in past years to solve this problem but without satisfactory results. Application of GRE-Lined Tubing for Asphaltene Control The operator decided to apply a novel strategy of using tubing internally lined with GRE based on its established ability to retard, and even eliminate, scale nucleation and deposition. The technology uses a thin-walled, solid-filament-wound GRE/fiberglass tube run inside carbon steel production tubing. Cement is pumped into the annulus between the steel tubing and the GRE liner. The ability to prevent asphaltene from sticking to the inner wall of the tubing is attributed to the smoother internal surface. It is also corroborated by a higher Hazen Williams coefficient value of 150 for GRE as compared with 110 for carbon steel pipe, which provides for lesser frictional pressure loss during flow. The GRE liners used by the operator have a surface roughness of 0.00011 in., which, unlike bare steel, is retained over the life of the GRE. The GRE-lined tubing proved to withstand temperatures of up to 280°F and hydrogen sulfide concentrations of up to 50%. This is comfortably more than the process conditions for the trial wells in consideration.

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Carpenter, Chris. "Polymer Application in High-Water-Cut Wells Enhances Productivity in a Mature Field". Journal of Petroleum Technology 73, nr 09 (1.09.2021): 60–61. http://dx.doi.org/10.2118/0921-0060-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200957, “Application of Specially Designed Polymers in High-Water-Cut Wells: A Holistic Well-Intervention Technology Applied in Umm Gudair Field, Kuwait,” by Ali Abdullah Al-Azmi, SPE, Thanyan Ahmed Al-Yaqout, and Dalal Yousef Al-Jutaili, Kuwait Oil Company, et al., prepared for the 2020 SPE Trinidad and Tobago Section Energy Resources Conference, originally scheduled to be held in Port of Spain, Trinidad and Tobago, 29 June–1 July. The paper has not been peer reviewed. A significant challenge faced in the mature Umm Gudair (UG) field is assurance of hydrocarbon flow through highly water-prone intervals. The complete paper discusses the field implementation of a downhole chemical methodology that has positively affected overall productivity. The treatment was highly modified to address the challenges of electrical-submersible-pump (ESP)-driven well operations, technical difficulties posed by the formation, high-stakes economics, and high water potential from these formations. Field Background and Challenge The UG field is one of the major oil fields in Kuwait (Fig. 1). The Minagish oolite (MO) reservoir is the main oil producer, contributing more than 95% of current production in the UG field. However, water cut has been increasing (approximately 65% at the time of writing). The increasing water cut in the reservoir is posing a major challenge to maintaining the oil-production rate because of the higher mobility of water compared with that of oil. The natural water aquifer support in the reservoir that underlies the oil column extends across the reservoir and is rising continuously. This has led to a decline in the oil-production rate and has prevented oil-producing zones from contributing effectively. The reservoir experiences water-coning phenomena, especially in high-permeability zones. Oil viscosity ranges from 2 to 8 cp, and hydrogen sulfide and carbon dioxide levels are 1.5 and 4%, respectively. During recent years, water production has increased rapidly in wells because of highly conductive, thick, clean carbonate formations with low structural dip as well as some stratified formations. Field production may be constrained by the capacity of the surface facilities; therefore, increased water production has different effects on field operations. The average cost of handling produced water is estimated to be between $5 billion and $10 billion in the US and approximately $40 billion globally. These volumes often are so large that even incremental modifications can have major financial effects. For example, the lift-ing cost of one barrel of oil doubles when water cut reaches 50%, increases fivefold at 80% water cut, and increases twenty-fold at 95% water cut.

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Carpenter, Chris. "Machine Learning Brings Vast Core-Analysis Legacy Data to Life". Journal of Petroleum Technology 74, nr 10 (1.10.2022): 97–99. http://dx.doi.org/10.2118/1022-0097-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31419, “Bringing Huge Core-Analysis Legacy Data to Life Using Machine Learning,” by Siti N.F. Zulkipli, SPE, Benard Ralphie, and Jamari M. Shah, SPE, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ Among the sources of subsurface data, rock and fluid analyses stand out as the best means of directly measuring subsurface properties. The implication of modeling this data into an organized data store means better assessment of economic viability and producibility in frontier basins and the capability to identify bypassed pay in old wells that may not have rock material. The complete paper presents agile technologies that integrate data management, data-quality assessment, and predictive machine learning (ML) to maximize company asset value with legacy core data. Introduction The complete paper integrates data gathering, data filtering, the connecting of scattered data, and the building of useful knowledge models using legacy core data from various operating assets. This integration is achieved by a data quality check (QC) work flow and ML to improve the definition of reservoir rock properties that affect field development and asset management. ML and deep-learning capabilities have been implemented to predict critical reservoir properties based on qualified legacy data. The work flow is aimed at bridging gaps in areas with limited core data coverage, reducing subsurface uncertainty and risk, and accelerating project delivery. In addition, data-prediction accuracy can be improved with ML applications as new data become available. Phase I: Data Preparation and Verification In this stage, more than 60,000 data points are gathered from 327 wells and grouped into different categories such as routine core analysis, special core analysis, geology, and rock mechanics. Leveraging on best practices in laboratory core analysis and subject-matter expert (SME) expertise, 88 QC rules are generated to delineate the data, identify outliers, and classify the data into good quality (labeled as 0), data requiring further QC (1), and rejected data (2). The generated QC rules target various rock properties such as porosity, permeability, capillary pressure, electrical properties, relative permeability, and rock mechanics. QC-rule implementation is an iterative process in which, after the initial screening, the rules are further optimized and enhanced to assist data classification based on practical experiences. These QC rules are needed because some observed data errors are related to data tabulation and incorrect naming. A total of 1,826 relevant variables, generated by different vendors, was extracted during QC-rule creation. These variables had to be merged in the QC process, which reduced the number of variables to 240.

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Carpenter, Chris. "Integrated Data Analysis Illuminates Commingled Smart Water-Injection Well". Journal of Petroleum Technology 74, nr 11 (1.11.2022): 67–69. http://dx.doi.org/10.2118/1122-0067-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206503, “Implementation and Intermediate Monitoring Outcomes of the First Commingled Updip Smart Water Injection Well in PA-B Platform Piltun-Astokhskoye Offshore Oil and Gas Field,” by Alexander V. Tsarenko, Valentin N. Tarsky, SPE, and Lisa Jane Robson, Sakhalin Energy Investment Company. The paper has not been peer reviewed. _ The objective of the complete paper is to share an evaluation of the background, drilling outcomes, and production and reservoir-pressure effects during 2 years of monitoring the first commingled updip smart water injector drilled in the Piltun area of the Piltun-Astokhskoye offshore oil and gas field in Sakhalin. The authors highlight details of the well-maturation decisions and expectations based on output of dynamic modeling studies. Setting The Piltun area consists of six main reservoir units (XXI-S, XXI-3, XXII-1, XXII-2, XXIII, and XXIV-2) being developed over two fault blocks (Block 1 and Block 2). All reservoirs have aquifers and gas caps, although the volumes, reservoir properties, and productivity of these reservoirs varies considerably, with the XXI-S and XXIV-2 reservoirs having the best rock properties and the highest recovery factors. Updip Water-Injection History In the original field development plan (FDP) created in 2008 and the reservoir management plan created in 2006, the Piltun area was to be developed by rows of commingled vertical downdip and updip water injectors (UDWIs), displacing oil to mid-rim vertical oil producers. However, the original UDWI concept was challenged early in development when the following geological surprises were encountered during drilling of the initial development wells: - The structure was significantly higher than expected at the crest of the field. - Thin, high-permeability (superfacies) layers were encountered in the producers and updip pilot holes. - The injectivity of the downdip injectors was much lower than expected and required an upgrade to the water-injection pumps. The FDP was reassessed in 2011. The design of the UDWIs was changed to long horizontal wells located at the gas/oil contact in the XXI-S, XXII-1, and XXIV-2 reservoirs only. The 2011 FDP assumed that early water breakthrough could be managed by smart-well technology in the oil producers. However, these producers experienced technical failures, and the plan to install smart completions in all mid-rim producers subsequently was aborted. In a 2015 FDP update, the design of the UDWIs was changed to vertical commingled wells equipped with a smart completion type, targeting only those reservoirs where clear incremental recovery and economic benefit was observed.

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Carpenter, Chris. "Mangrove Restoration and Conservation Effort in Niger Delta Used as Carbon Offset Option". Journal of Petroleum Technology 75, nr 07 (1.07.2023): 104–6. http://dx.doi.org/10.2118/0723-0104-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207725, “Mangrove Restoration and Conservation as a Carbon Offset Option: a Case Study in the Niger Delta Region,” by Gustavo C.D. Estrada, Jason Sali, and Patrizio Piras, Eni, et al. The paper has not been peer reviewed. _ Mangroves have gained attention as a carbon offset option because of their high carbon-storage capacity and diverse social and environmental benefits. Carbon stock in mangroves is approximately four times higher than in terrestrial forests and contributes to almost 10% of the global terrestrial carbon pool. In 2017, the Nigerian Agip Oil Company (NAOC) launched an initiative to restore mangroves to promote social and biodiversity benefits while contributing to offsetting its greenhouse-gas (GHG) emissions. The complete paper details the methodology and results of this initiative. Introduction Mangroves are coastal ecosystems mainly composed of typical tree and shrub plant species possessing adaptations to unstable, low-oxygen soil; high-salinity water; and frequent submersion. Fauna equally adapted to the unique environmental conditions observed in the mangroves also are considered part of the ecosystem. Mangrove forests are recognized globally to be of extreme ecological, economic, social, and cultural importance because of the variety of goods and services they provide. Some of these include the protection of the coastline from the energy of the winds and waves and conservation of fishing and biodiversity in coastal and adjacent estuarine waters. The literature suggests that more than 812,000 ha of mangrove areas, spread over 106 countries or territories, show potential for restoration. Furthermore, mangroves have been lost globally at a rate of 1–2%/year, which may account for an annual emission of approximately 0.09–0.45 GtCO2eq/year that could be avoided through conservation. Because the dispersion of mangroves propagules (seeds that have germinated while attached to the mother plant) is driven by ocean and estuarine currents, natural recolonization can occur and mangroves recover successfully by secondary succession during a period of 10–15 years if conditions are ideal. However, ecosystem function may take more than a century to be fully reinstated. Understanding the autoecology, hydrological patterns, and factors impairing natural regeneration is key for a successful restoration project. Several examples exist of restoration programs that were unsuccessful for, among other problems, having failed to acquire these key prerestoration data. During the last 10–15 years, a community-based ecological mangrove restoration effort has emerged based on the recognition that ecological science is not enough to assure successful restoration of mangroves and that social and economic issues must also be integrated.

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Soefje, Scott, Corinne Carpenter, Katherine Carlson, Samir Awasthi, Thomas S. Lin, Shuchita Kaila, Daniel Tarjan i in. "Clinical Administration Characteristics of Subcutaneous and Intravenous Administration of Daratumumab in Multiple Myeloma Patients at Mayo Clinic". Blood 138, Supplement 1 (5.11.2021): 2717. http://dx.doi.org/10.1182/blood-2021-149012.

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Abstract Introduction: Daratumumab is approved across lines of therapy for multiple myeloma (MM) by subcutaneous administration (DARA SC) or by intravenous administration (DARA IV). In clinical studies, the administration time ranges from 3-5 minutes for DARA SC versus 3-7 hours for DARA IV, and DARA SC is associated with reduced rates of administration-related reactions (ARRs). These characteristics of DARA SC are associated with benefits for clinics in terms of safety and clinic time. We previously reported DARA administration characteristics at Mayo Clinic infusion centers: DARA SC had shorter total clinic and total chair times compared with DARA IV, and DARA SC was associated with very low rates of ARR-related events (Soefje S, et al. EHA Library. 2021). Based upon this analysis, the treatment plan was modified to reduce the mandated observation time for DARA SC to improve clinic efficiency. Here, we describe updated clinical administration characteristics for DARA SC at Mayo Clinic infusion centers before and after the reduction in procedure-mandated observation time, versus DARA IV, using a novel empirical data extraction approach from Electronic Health Records (EHR). Methods: Patients ≥18 years of age with an ICD-9/10 diagnosis code of MM and a first DARA treatment between April 5, 2017 and June 22, 2021 were identified in Mayo Clinic's EHR database. Data were extracted using a scheduling and pharmacy software that tracked patient movement through appointments at a Mayo Clinic infusion center. On May 3, 2021, the Mayo treatment plan was amended to shorten the mandated post-administration observation time for DARA SC from 4 to 2 hours for Dose 1 and from 1 hour to 30 minutes for Doses 2 and 3, with no mandated observation time for Doses 4+. In this analysis, data were captured for patients initiating DARA IV throughout the defined treatment window. For DARA SC, data were captured for patients starting DARA SC therapy on the initial treatment plan (before May 3, 2021; DARA SC initial) and after the change to shorten the mandated post-administration observation time for DARA SC (after May 3, 2021; DARA SC shortened). Time-based measures included: total clinic time (check-in time through patient check-out); total chair time (time from infusion room entry to infusion room exit or check-out time, including order review, pharmacy preparation time, and post-administration observation time); and observation time (time from the end of medication administration to infusion room exit or patient check-out). The medication administration time documented for DARA SC was 0 minutes due to the default duration for SC injections in the EHR. Results: In total, 755 (DARA IV, n=586; DARA SC initial, n=145; DARA SC shortened, n=24) patients received DARA treatment for MM. For all doses combined, the median total clinic time was 2.9 hours shorter for DARA SC compared with DARA IV (DARA IV, 4.9 hrs; DARA SC initial, 2.0 hrs). The median total clinic time for DARA SC and DARA IV was highest at Dose 1 (DARA IV, 9.5 hrs; DARA SC initial, 6.1 hrs; DARA SC shortened, 4.4 hrs) and lower for subsequent doses (Dose 4+: DARA IV, 4.6 hrs; DARA SC initial, 1.7 hrs; DARA SC shortened, 1.6 hrs; Figure). Similarly, the median total chair time was 2.7 hours shorter in the DARA SC group compared with the DARA IV group for all doses combined (DARA IV, 4.1 hrs; DARA SC initial, 1.4 hrs). The median total chair time for DARA SC and DARA IV was highest at Dose 1 (DARA IV, 8.8 hrs; DARA SC initial, 5.6 hrs; DARA SC shortened, 3.9) and lower for subsequent doses (Dose 4+: DARA IV, 3.7 hrs; DARA SC initial, 1.1 hrs; DARA SC shortened, 1.1 hrs). Conclusion: Marked reductions in the amount of time spent both in clinic and in chair were observed with DARA SC compared with DARA IV, with additional time savings observed following the Mayo procedure change to reduce the DARA SC mandated observation time. These favorable DARA SC administration characteristics may indicate a reduction in the burden on both clinical resources and patients in Mayo Clinic infusion centers. These results add to the growing body of evidence supporting the use of DARA SC as an efficient and convenient treatment administration option for patients with MM. Figure 1 Figure 1. Disclosures Soefje: Beigene: Consultancy; Pfizer: Speakers Bureau; Janssen: Consultancy, Research Funding. Carpenter: nference Inc.: Current Employment; Janssen: Consultancy. Carlson: nference Inc.: Current Employment; Janssen: Consultancy. Awasthi: nference Inc.: Current Employment, Current holder of individual stocks in a privately-held company; Janssen: Consultancy. Lin: Janssen: Current Employment. Kaila: Janssen Scientific Affairs, LLC: Current Employment. Kayal: nference Inc.: Current Employment; Janssen: Consultancy. Kirkup: nference Inc.: Current holder of individual stocks in a privately-held company, Ended employment in the past 24 months; Path AI: Current Employment, Current holder of individual stocks in a privately-held company, Current holder of stock options in a privately-held company. Wagner: nference Inc.: Current Employment; Janssen: Consultancy. Gray: Janssen Scientific Affairs, LLC: Current Employment, Current holder of individual stocks in a privately-held company. Kumar: Oncopeptides: Consultancy; Celgene: Membership on an entity's Board of Directors or advisory committees, Research Funding; Carsgen: Research Funding; Antengene: Consultancy, Honoraria; Janssen: Consultancy, Membership on an entity's Board of Directors or advisory committees, Research Funding; KITE: Consultancy, Membership on an entity's Board of Directors or advisory committees, Research Funding; Merck: Research Funding; Astra-Zeneca: Consultancy, Membership on an entity's Board of Directors or advisory committees, Research Funding; Novartis: Research Funding; Bluebird Bio: Consultancy; Beigene: Consultancy; Tenebio: Research Funding; Roche-Genentech: Consultancy, Research Funding; Takeda: Consultancy, Membership on an entity's Board of Directors or advisory committees, Research Funding; Amgen: Consultancy, Research Funding; BMS: Consultancy, Research Funding; Abbvie: Consultancy, Membership on an entity's Board of Directors or advisory committees, Research Funding; Adaptive: Membership on an entity's Board of Directors or advisory committees, Research Funding; Sanofi: Research Funding.

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Carpenter, Chris. "Analytical Work Flows Enable Continuous Waterflooding Optimization for a Mature Field". Journal of Petroleum Technology 73, nr 01 (1.01.2021): 55–56. http://dx.doi.org/10.2118/0121-0055-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198586, “A New Continuous Waterflood Operations Optimization for a Mature Oil Field by Use of Analytical Work Flows That Improve Reservoir Characterization,” by Atul Yadav and Anton Malkov, SPE, Wintershall, and Essam Omara, Suez Oil Company, et al., prepared for the 2019 SPE Gas and Oil Technology Showcase and Conference, Dubai, 21–23 October. The paper has not been peer reviewed. In the complete paper, the authors present a novel approach that uses data-mining techniques on operations data of a complex mature oil field in the Gulf of Suez that is currently being waterflooded. Evidence is presented about how salinity data can be used to further justify the linkages between different wells obtained from cross-correlation analysis. The results presented in this research can be adapted to any waterflooded field to optimize recovery at frequent intervals where injection and production data are available continuously. Introduction Mature oil fields typically present challenges of increased water production and water handling. Considering the geological complexity and associated field-performance behavior, reservoir characterization to optimize water flooding is a major challenge. An integrated reservoir study was con ducted to minimize reservoir uncertainties and increase understanding of the field’s performance behavior. The acceptable history-matched model was used to estimate remaining oil potential, maintain and increase current production levels, and optimize the water-injection rate. Generally, history-matched models need to be updated throughout the life of producing fields as new subsurface data are acquired. Such integrated reservoir modeling studies, however, can be time-consuming and do not necessarily enable quicker decision-making around operational activities. The continuous recording of production and injection data presents new opportunities to apply novel analytical techniques to understand interwell connectivity in the reservoir. The current ability to store and analyze data, coupled with advances in the ability to interpret big data sets, has helped create an independent toolkit that provides analysis without the geological model. In addition, geological information such as pre-existing faults and the commingled or disconnected nature of production between different layers can be integrated to obtain and improve analyses from the analytical models. The authors analyze the results using Pearson’s cross-correlation analysis measure to obtain a qualitative analysis of the field. They also apply Spearman’s rank correlation analysis for the discussed field (henceforth named GOS for purposes of this paper) that helps compare injection and production data. The objective is to present a comparison between the analytical and the stream-lined approach to show consistency in reservoir characterization. The effective injector/producer pairs identified form an important component of the field development.

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Carpenter, Chris. "Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons". Journal of Petroleum Technology 73, nr 08 (1.08.2021): 51–52. http://dx.doi.org/10.2118/0821-0051-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.

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Carpenter, Chris. "Autonomous ICDs Optimize Production in Singue Field, Ecuador". Journal of Petroleum Technology 75, nr 04 (1.04.2023): 64–66. http://dx.doi.org/10.2118/0423-0064-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210417, “Autonomous ICD Introduction in Singue Field, Ecuador: Completion Methodology and Production Evaluation,” by Alejandro Chacon, SPE, Georgina Corona, and Juan Pico, Halliburton, et al. The paper has not been peer reviewed. _ Autonomous-inflow-control-device (AICD) technology, design methodology, and production-performance evaluation for AICD completions were applied for the first time in multiple horizontal wells of the Singue oilfield development in Ecuador. The analysis described in the complete paper covered the complete cycle, from reservoir modeling, completion design, post-drilling match, calibration, and production-performance analysis. Background and Field Information Singue is a field in a tropical rainforest in the Sucumbios province of Ecuador. The first well in the Singue field was drilled in February 1991. Lower U was the target reservoir in this first well. The well was drilled on the basis of seismic 2D data acquired from 1979 to 1989. Field cumulative oil production between 1991 and 1997 was 447,000 bbl. The field then was shut in until 2012, when Gente Oil Company was assigned as the operator of Block 53. Despite heavy field-development investment, a cumulative oil production of 8 million bbl was generated until 2018. Alternate completion techniques were considered to increase oil production by drilling horizontal wells. Water breakthrough was the challenge in these wells. The field has strong support from a water aquifer. An additional challenge in this area was the environmental sensitivity of the Amazon region to produced-water disposal. A horizontal completion with inflow-control technology to restrict water was considered as a mitigation measure. The first horizontal well, AH1, was drilled in 2019; it included swell packers and AICDs to balance the oil and control and restrict water at breakthrough. The second well, BH2, was drilled in 2020; the third and fourth wells were drilled in 2021 with similar completion technology. These wells were drilled in the Lower U reservoir, which has an average oil API gravity of 22.8. This reservoir is considered a consolidated sandstone with no sand production. Fluidic-Diode AICD Technology AICDs have a similar performance to traditional ICDs during the initial oil-production phase of the well before the onset of unwanted fluids (water/gas). During oil production, AICDs induce a low-pressure differential that allows balancing the flow across the completion. Therefore, they also provide the benefit of delaying the onset of water or gas. However, this technology offers additional benefits. In contrast to ICDs, AICDs induce a higher restriction for water or gas by creating a greater pressure differential across the devices for these fluids, which reduces the flow rate when compared with traditional ICDs.

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Carpenter, Chris. "Alternative Business Model of CCS Projects Unlocks High-CO2 Fields". Journal of Petroleum Technology 75, nr 12 (1.12.2023): 56–59. http://dx.doi.org/10.2118/1223-0056-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214359, “Business Model of Carbon Capture and Storage (CCS) Projects for High-CO2 Fields,” by Hasnor Lot, SPE, Andrew Yeow, SPE, and Anuar Buang Mahmood, SPE, Petronas, et al. The paper has not been peer reviewed. _ High-CO2 gas fields present a problem to host governments wanting to both ensure security of supply and achieve net-zero aspirations. While carbon capture and storage (CCS) technology holds the promise of technical feasibility to unlock these fields, its commercial success ultimately hinges on the choice of an appropriate business model. This study compares the economics of the traditional business model [i.e., CCS as part of the upstream petroleum operation dedicated to a production sharing contract (PSC)] vs. the alternative business model [i.e., a regional CCS hub separately managed by a special-purpose vehicle (SPV)]. For simplicity, this paper uses the term CCS throughout, although the discussions apply equally well to carbon capture, usage, and storage projects. Background Gas Value Chain and the Cost of Gas (COG). With its higher development, transportation, and processing costs; longer and flatter production profile; and needs for network infrastructure, the economics of gas development is often less robust than that of oil. Therefore, gas development requires not only the establishment of long-term contracts and a complex value chain but also active government support in the form of friendly fiscal and tax regimes and a fair gas-pricing policy. In addition to its role as the upstream regulator, a national oil company (NOC) may also participate in the gas market as an aggregator. Effectively, the NOC signs an upstream gas-sales agreement (UGSA) with upstream contractors committing to buy gas at a volume and price palatable to them. The aggregator then sells the gas it now owns to downstream users. The margin between the buying and selling prices makes up the aggregator’s profit. In return, the aggregator takes on the intermediary roles of matching supply to demand, coordinating fair nomination and curtailment mechanisms, and ensuring that the gas chain as a whole is flexibly robust against operational disruptions. An NOC enjoys the dual roles of operating as a national corporation and acting as the upstream regulator. In its regulatory role, the NOC is cognizant of the need to allocate the risks and rewards of a CCS investment in a fair and efficient manner between participating parties. The business model must improve the overall economic return for both the upstream contractor and the SPV while enhancing the NOC’s integrated value. The business model so designed must also achieve the NOC’s longer-term goal of unlocking resource opportunities and monetizing stranded gas fields.

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Carpenter, Chris. "Dual Heuristic Dynamic Programming Enables Trajectory Tracking Control". Journal of Petroleum Technology 75, nr 05 (1.05.2023): 76–78. http://dx.doi.org/10.2118/0523-0076-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200271, “Dual Heuristic Dynamic Programming in the Oil and Gas Industry for Trajectory Tracking Control,” by Seaar Al-Dabooni, Basra Oil Company; Alaa Azeez Tawiq, Technical Institute of Basra; and Hussen Alshehab, Basra Oil Company. The paper has not been peer reviewed. _ The complete paper presents an artificial intelligence (AI) algorithm the authors call dual heuristic dynamic programming (DHDP) that is used to solve optimization-control problems. Fast, self-learning control based on DHDP is illustrated for trajectory-tracking levels on a quadruple tank system (QTS) consisting of four tanks and two electrical pumps with two pressure-control valves. Two artificial neural networks are constructed for the DHDP approach: the critic network (the provider of a critique or evaluated signals) and the actor network or controller (the provider of control signals). The DHDP controller is learned without human intervention. Approximate Dynamic Programming (ADP) Recently, many different types of artificial algorithms have been applied in petroleum fields to solve optimization problems. This complete paper introduces a new field of AI applicable to oil and gas, ADP. ADP is a useful tool to overcome the behavior of nonlinear systems and is a special algorithm of reinforcement learning (RL). The authors write that ADP can be viewed as consisting of three categories: heuristic dynamic programming (HDP), DHDP, and globalized HDP. ADP features two neural networks—an actor and a critic—to provide an optimal control signal and long-cost value, respectively. ADP has numerous applications. The complete paper references work that discusses control on turbo-generator and swarm-robot problems by use of DHDP and that illustrates that action-dependent HDP can obtain an optimal path by multirobot navigation. QTS is frequently used in the oil and gas industry. DHDP is used to control the voltage of the two pumps to follow the desired level (set-point-level value) of the tanks, an approach that can learn by itself (a self-learning controller). The complete paper devotes several pages to equations and parameters that describe HDP. In ADP, optimal control problems are solved, thereby allowing agents to select an optimal action to minimize a long-term cost value through solution of Bellman’s equation. RL and ADP are used to train the actor neural network to provide optimal actions based on minimizing the cost-to-go value produced from the critic network. The actor function approximator is denoted for the actor neural network. After full training of these networks, the optimal action values are obtained from the actor network. System Functionality The equipment receives the system states of the process through sensors, and the algorithm maximizes the reward by selecting the correct optimal action (control signal) to feed the equipment. The simulation results for applying DHDP with QTS as a benchmark test problem were obtained using MATLAB. QTS is illustrated as an example in the paper because QTS is widely used in most petroleum exploration or production fields as an entire system or in parts. Another reason for the authors’ choice of QTS as a test problem is that QTS features a difficult model to control that has a limited zone of operating parameters to be stable. The multi-input/multioutput (MIMO) model of QTS was a similar model as most MIMO devices in the oil and gas field. The overall learning-control-system performance was tested and compared with HDP and a well-known industrial controller, a proportional integral derivative (PID) using MATLAB programming. The simulation results of DHDP provide enhanced performance compared with the PID approach, with a 98.9002% improvement.

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Carpenter, Chris. "Wellhead Design Enables Offline Cementing and a Shift in Operational Efficiency". Journal of Petroleum Technology 73, nr 05 (1.05.2021): 68–69. http://dx.doi.org/10.2118/0521-0068-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202439, “Pushing Malaysia’s Drilling Industry Into a New Frontier: How a Distinctive Wellhead Design Enabled Implementation of a Fully Offline Well Cementing Resulting in a Significant Shift in Operational Efficiency,” by Fauzi Abbas and Azrynizam M. Nor, Vestigo, and Daryl Chang, Cameron, a Schlumberger Company, prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Traditionally, rigs are positioned over a well from the moment the surface casing is drilled until the installation of the wellhead tree. This results in the loss of precious time as the rig idles during online cementing. However, in mature Field A offshore Terengganu, Malaysia, a new approach eliminated such inefficiency dramatically. Operational Planning With oil production in Field A initiated in October 2015, historical data on well lithology, formation pressure, and potential issues during drilling were available and were studied to ensure that wells would not experience lost circulation. This preplanning is crucial to ensure that the offline cementing activity meets the operator’s barrier requirements. Petronas Procedures and Guidelines for Upstream Activities (PPGUA 4.0) was used for the development of five subject wells in Field A. In this standard, two well barriers are required during all well activities, including for suspended wells, to prevent uncontrolled outflow from the well to the external environment. For Field A, two barrier types, mechanical and fluid, allowed by PPGUA 4.0 were selected to complement the field’s geological conditions. As defined in PPGUA 4.0, the fluid barrier is the hydrostatic column pressure, which exceeds the flow zone pore pressure, while the mechanical barrier is an element that achieves sealing in the wellbore, such as plugs. The fluid barrier was used because the wells in Field A were not known to have circulation losses. For the development of Field A, the selected rig featured a light-duty crane to assist with equipment spotting on the platform. Once barriers and rig selection are finalized, planning out the drill sequence for rig skidding is imperative. Space required by drillers, cementers, and equipment are among the considerations that affect rig-skid sequence, as well as the necessity of increased manpower. Offline Cementing Equipment and Application In Field A, the casing program was 9⅝×7×3½ in. with a slimhole well design. The wellhead used was a monobore wellhead system with quick connectors. The standard 11-in. nominal wellhead design was used for the wells with no modifications required. All three sections of the casing program were offline cemented. They were the 9⅝-in. surface casing, 7-in. production casing, and 3½-in. tubing. The 9⅝-in. surface casing is threaded to the wellhead housing and was run and landed with the last casing joint. Subsequent wellhead 7-in. casing hangers and a 3½-in. tubing hanger then were run and landed into the compact housing.

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Carpenter, Chris. "Downsizing, Use of Dummy and Venturi Valves Enhance Gas Lift Performance". Journal of Petroleum Technology 75, nr 10 (1.10.2023): 90–92. http://dx.doi.org/10.2118/1023-0090-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213975, “Gas Lift Performance Enhancement Strategies by Downsizing and Using Dummy and Venturi Valves: A Paradigm Shift in Gas Lift Systems Management Philosophy,” by Wael F. Akeil, Ahmed M. El-Bohoty, and El-Sayed I. Abd El-Mawla, Gulf of Suez Petroleum Company, et al. The paper has not been peer reviewed. _ A mature offshore Egyptian field has entered a depletion phase. Most of its gas lift design bases were initiated during production startup and feature standardized sets of large gas lift valve port sizes with narrow spacing. Inconsistent well flow during reservoir depletion adds complications to the system. Therefore, a screenout model was created to select candidate wells for downsizing and for changing out with dummy and Venturi valves. After screening, 70 wells were selected for application of the new strategy. The complete paper discusses the effectiveness of smaller port sizes and the use of dummy and Venturi valves in enhancing gas lift performance and maximizing recovery. Field Background The field is divided into four main geographical quadrants, each with its own facilities. Total production currently is approximately 60,000 BOPD with an average water cut of 85%. Exploration and development of the field saw the drilling of more than 460 wells; half of these currently are experiencing reservoir pressure decline, drained reserves, or operational problems. Most wells are gas lifted, and the remainder either use electric submersible pump (ESP) installation or flow naturally. The facility consists of 73 offshore satellite platforms containing the wells—both oil producers and water injectors—connected to nine offshore complex platforms. As a part of continuous improvement trials, the operator reviewed the process of gas lift system management to introduce necessary improvements and recommend changes for long-term plans. The proposed amended management system was the result of monitoring, troubleshooting, and optimization activities outlined in the complete paper. Amended Gas Lift Management System Using Dummy Valves in Gas Lift System. Conceptual Phase. A dummy valve is a special gas lift valve shaped like solid metallic bar with upper and lower packings. They are installed to replace unloading valves that are no longer needed. Installing dummy valves instead of the unloading valves can reduce problems such as valve interference and deepens the point of gas injection. Redesign Procedure Based on the New Production Profile. This practice can be applied in two main cases: First, if reservoir pressure has declined and the well is producing with a lower rate but the surface injection pressure is still high enough to reach deeper valves; and, second, if the well is planned to be recompleted from one formation to another that has a higher reservoir pressure but with lower formation feed as the result of lower productivity. The main steps for redesign are provided in the complete paper.

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Carpenter, Chris. "Combined Mud-Cooling, MPD Techniques Enable HP/HT Drilling in Egypt". Journal of Petroleum Technology 75, nr 03 (1.03.2023): 79–82. http://dx.doi.org/10.2118/0323-0079-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210252, “Drilling the Deepest HP/HT Onshore Exploration Well Using a Combination of Mud-Cooling and MPD Techniques: A Field Case Study From the Nile Delta of Egypt Targeting a Mesozoic Carbonate Platform,” by Mahmoud El-Husseiny, Egyptian Natural Gas Holding Company, and Taher Elfakharany, Al-Azhar University. The paper has not been peer reviewed. _ The complete paper reviews the successful application of a mud-cooling and managed-pressure-drilling (MPD) system in a high-pressure/high-temperature (HP/HT) well to explore the potential of the Mesozoic carbonate platform with a pressure ramp and narrow mud-weight window (NMWW) in the Nile Delta. The constant bottomhole pressure (CBHP) variation of MPD in combination with mud cooling was used to drill from the middle of the pressure ramp to the target depth, maintaining the mud-inlet temperature at approximately 50°C. Geological Targets and Geohazards The primary objective of Well T-1 is the edge of a Mesozoic carbonate platform. These carbonates are expected to be high-energy shallow marine deposits with fair reservoir properties (20–50% net-to-gross, 5–10% porosity). The secondary objectives are turbiditic sandstone channels of the Oligocene. These sandstones are expected to have 9–20% porosity and 50–300 md permeability. Potential Middle and Late Miocene geohazards include pressure rampup associated with losses, kicks, and borehole degradation, including tight holes, overpull, and caves; and reported sticking and hangup events. The HP domain begins below approximately 4000 m. Potential Oligocene to Paleocene geohazards include NMWWs associated with losses, kicks, and simultaneous gains and losses (ballooning); borehole degradation, including tight holes, overpull, and caves; and sticking and hangup events. The HP and HT domains begin below approximately 4500 m. Potential Mesozoic carbonate geohazards include possible losses of fractured and pressure-regressed carbonates. Mud-Cooling Technique Concept and Equipment The mud cooler consists of two circuits. In the first, hot mud is circulated through a dual mud cooler using a centrifugal pump. Because of heat exchange through the plate heat exchanger, the mud is cooled and transferred back into the active mud system. The discharge of cold mud takes place upstream of the point where the suction of hot mud occurs. In the second circuit, a fluid mixed with water and glycol is circulated between a dual air cooler and the dual mud cooler using a dedicated pump. When passing through the plate heat exchanger, this mixture of water and glycol is evacuated. When this mixture returns to the dual air cooler, it is cooled using high-performance ventilators. The mud-cooling system features 16 ventilators. The efficiency of the mud-cooling system is adjusted with a number of operated ventilators. The mud-cooling units used in this well consist of two dry air coolers and two sets of air fans (Fig. 1), with each set containing 24 fans. A mixture of 10% glycol and water was used as a cooling fluid.

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Carpenter, Chris. "Wave Energy Converters Hold Key to Using Renewables for Subsea Power". Journal of Petroleum Technology 75, nr 08 (1.08.2023): 55–57. http://dx.doi.org/10.2118/0823-0055-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210910, “Innovative Industry Lead Project for Renewables for Subsea Power,” by Ian R. Crossland, SPE, Mocean Energy; Paul Slorach, Verlume; and Andrea Caio, Mocean Energy, et al. The paper has not been peer reviewed. _ The levels of power required to operate an offshore oil and gas field with 100% renewable energy are such that even offshore wind is unlikely to cost-effectively provide the levels of uptime needed to maintain reliable production without some form of energy storage. Providing a combination of technologies to maintain a balanced renewable energy supply system is key. In the complete paper, the authors focus on the use of wave energy converters (WECs), in combination with energy storage, to deliver benefits when powering offshore assets in situ, especially when continuous power requirements are in the 10–100 kW range. Introduction In 2020, a UK industry collaborative project, Renewables for Subsea Power (RSP), was launched and co-funded by the Net Zero Technology Centre. RSP is a phased demonstration project involving three technology developers (Mocean Energy, Verlume, and Modus), a first-tier international services company (Baker Hughes), and a major North Sea operator (Harbour Energy). Given the focus on ramping up the energy transition, in 2022 another major North Sea operator (Serica Energy) and an autonomous resident vehicle supplier (Transmark Subsea), who replaced Modus, also joined the project as part of the final phase (Phase 3) of activities. RSP aims to develop a complete, fully integrated system for the provision of the following: - Low-carbon remote power and communications using a WEC as the effective power source - A subsea energy-storage system for power conditioning - Smooth and uninterruptable power delivery to subsea production control systems - Residential underwater vehicles for a variety of monitoring or maintenance activities Throughout the three phases of RSP, project partners will design, build, and test all elements of the combined system. Phase 1 consisted of a front-end engineering design (FEED) successfully completed in 2021. Phase 2 involved the building and onshore commissioning of various subsystems. Phase 3 is planned to culminate in offshore full-system deployment and trials during 2023. Benefits of Wave Energy At a macro level, ocean waves are a highly abundant source of energy. Technically extractable wave energy resources amounted to 5–23% of 2017 global electricity demand, for instance, and approximately seven times that of available tidal resources worldwide. With approximately 40% of the world’s population inhabiting coastal regions, waves also provide a relatively local source of power for many coastal communities and densely populated areas. As well as being energy-dense and abundant, wave resource is predictable, often days in advance compared with solar and wind. In addition, its daily and seasonal complementarity with other renewables is crucial to achieving a more-balanced grid.

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Carpenter, Chris. "Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait". Journal of Petroleum Technology 76, nr 07 (1.07.2024): 96–99. http://dx.doi.org/10.2118/0724-0096-jpt.

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_ 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. _ 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. Introduction 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. Development of Business Cases 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. 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). Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best. North Kuwait (NK) Business Case. 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. 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, of approximately 60 ft; and Lower, of approximately 16 ft). The reservoir exhibits porosity of approximately 14% and permeability of approximately 14 md and is filled with relatively-low-API hydrocarbon (19–22 °API).

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Carpenter, Chris. "Dual-Frequency Desalting Technology Breaks Bottlenecks, Lowers Cost of Ownership". Journal of Petroleum Technology 74, nr 12 (1.12.2022): 64–66. http://dx.doi.org/10.2118/1222-0064-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22365,“No More Inefficient Crude Desalting: Breaking Bottlenecks With Dual-Frequency Technology Lowering Total Cost of Ownership,” by Prabhu Elumalai, Gary Sams, and Umanath Subramani, Schlumberger, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ A major independent crude oil refinery in Asia is processing crude oil in two crude distillation units (CDUs) using an alternating-current (AC) desalting system. Because of inefficient desalting, only 60% desalting efficiency was achieved for each train with subsequent low dehydration efficiency. After a holistic review of the entire desalting operation, the service company recommended upgrading the CDU 1 desalter vessel to dual-frequency technology and adding a new dual-frequency desalter at the second stage of the CDU 2 vessel. The complete paper examines the successful project from early engagement through project execution leading. Refinery Desalters _ Overview of Case-Study Refinery. The refinery was operated with a design capacity of 206,000 B/D through CDUs 1 and 2. CDU 1 included two trains of two-stage legacy AC desalters (Trains 1 and 2). Train 1 operated with 40% of CDU 1’s total flow (60,000 BOPD), while Train 2 operated with 60% of CDU 1’s total flow (90,000 BOPD). The AC desalting system desalted and dehydrated crude oil before feeding the crude to preheated trains. The desalters in this refinery operated for 20 years with the AC technology. Dual-Frequency AC/Direct Current (DC) Desalter Configuration. AC crude dehydration technology is over a century old. The complete paper recaps different types of AC desalter configurations, but this synopsis concentrates on dual-frequency AC/DC desalter configurations. The vessel design for the dual-frequency technology is identical to that of the AC/DC vessel, with similar spreaders, electrodes, and collectors. What differentiates the dual-frequency technology is the power unit, which functions with two frequencies for dehydration and desalting. The base frequency typically is in the range of 800–1,600 Hz, and the modulation frequency is in the range of 0.5–4 Hz. The computer-based controller controls the output of the variable voltage/frequency power unit and produces a nearly infinite number of waveform configurations. Also, these units facilitate online changing of maximum voltage, minimum voltage, base frequency, and modulation frequency applied to the electrode. Conventional power units cannot be operated beyond 40% of their rating. The dual-frequency power unit, however, can operate successfully beyond 80% of its rating. The combination of AC/DC fields with dual-frequency performance provides the high water tolerance of the AC field, the high efficiency of the DC field, and the improved desalting offered by the dual-frequency voltage pattern. This combined electrostatic technology offers more-efficient bulk water and small-water-droplet removal from the crude oil. Highly efficient dehydration means smaller treaters, better performance, lower operating temperatures, and fewer demulsifier chemicals. Further improvements include optimized electrode configurations and enhanced fluid distribution inside the electrostatic treaters.

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Carpenter, Chris. "Integrated Approach Optimizes Underground Gas-Storage Process". Journal of Petroleum Technology 75, nr 04 (1.04.2023): 51–54. http://dx.doi.org/10.2118/0423-0051-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207941, “Underground Gas-Storage Process Optimization Using Integrated Subsurface Characterization, Dynamic Modeling, and Monitoring: A Case Study,” by Longxin Li, Yuan Zhou, and Limin Li, PetroChina Southwest Oil and Gasfield Company, et al. The paper has not been peer reviewed. _ The operator’s Xiangguosi (XGS) gasfield facility began underground gas storage (UGS) operations in a depleted gas field in southwest China in 2013. Following this initial period, the site was reassessed to increase deliverability safely during the winter months to meet future peak gas demand. The results of that analysis informed the resulting system design, in combination with fit-for-purpose reservoir-surveillance systems; caprock-seal recording pressure, rock deformation, and seismicity data in real time; and regular wellbore inspection. Introduction The XGS UGS facility currently operates in a previously depleted gas reservoir in Sichuan province. Its construction took place during the second half of 2011; cushion gas injection started in June 2013. Located in a high-tectonic-stress region, the geological setting of the XGS field is structurally complex and highly faulted and the targeted carbonate formation is heterogeneous and naturally fractured. When the studies described in the complete paper commenced in November 2019, the field hosted 22.80×108 m3 of working gas along with 19.80×108 m3 of cushion gas. As of May 2020, the reservoir had completed eight injection and six withdrawal cycles and delivered a maximum withdrawal rate of 21.96×106 m3/d. The UGS conversion plans required a revisit to analyze the possibility of increasing the withdrawal rate to 28.55×106 m3/d, thereby positioning better for future peak gas demand. The drilling of five new wells commenced in 2019. Planned Technical Approach The purpose of the study was to optimize the XGS UGS facility’s working gas capacity and improve operational performance throughout asset life. It was proposed to achieve this by 4D geomechanical and 3D dynamic flow-simulation models. The geomechanical model would hinge on an integrated subsurface characterization work flow combined with an advanced monitoring network tightly connected with the surface facility operation to ensure maximum containment and optimal injection and withdrawal rates and volumes. This holistic approach would aid in ascertaining optimal drawdown pressures to minimize rock fatigue and ensure operation of the UGS facility within safe pressure limits. Fully integrated Subsurface Characterization A detailed review of the existing petrophysical interpretation from wells calibrated with core analysis data was undertaken. Petrophysical interpretations from 29 wells were used to construct a reservoir classification and petrophysical property models. This led to the understanding that depositional facies were not the overriding control on reservoir quality in this case because the reservoir is highly affected by karstification, diagenesis, and fracturing. Prestack migrated seismic data was improved with acquisition footprint, noise, and multiple removal and then interpreted to map subsurface structure. The edited well logs were used to build synthetic seismograms. A complex structural model was created that included 22 stratigraphic zones and a detailed fault model within the main field structure, integrating stratigraphic data and log curves from all recently drilled wells.

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Carpenter, Chris. "Study Investigates Ineffectiveness of Acid Fracturing for Tight Reservoir Rock". Journal of Petroleum Technology 75, nr 06 (1.06.2023): 60–62. http://dx.doi.org/10.2118/0623-0060-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209264, “Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil Company, and Iraj Ershaghi, SPE, University of Southern California. The paper has not been peer reviewed. _ The complete paper describes the analysis of actual performance data for acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. An included case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1–5 md. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells indicates no fracture flow and very limited stimulated production. Background A category of tight conventional reservoir rocks exists that has not been subjected to horizontal drilling and multistage fracturing. The objective of the authors’ study is to analyze the ineffectiveness of treatment response under acid fracturing and explore the potential of implementing multistage fracturing for a tight reservoir rock using experience gained from unconventional resources. The subject reservoir is a tight carbonate of the Middle Cretaceous age with porosity ranges between 15 and 19% and an average thickness of approximately 90 ft. Oil viscosity ranges between 2.06 and 2.54 cp and average oil gravity is 25° API. The reservoir is a depletion-drive type where the main natural energy is provided by gas in solution. Among the initial wells, only six were successful. The field is very complex, based on stratigraphic and structural characteristics. The first horizontal well was drilled during 2015–16 and was subjected to seven-stage acid fracturing. This resulted in a substantial increase of well cumulative production compared with that of vertical wells. The development plan of this field was implemented with horizontal wells with laterals extending approximately 3,000 ft. Each well was subjected to multistage acid fracturing. Examination of performance data indicated that producing wells suffered from rapid pressure depletion after a production period of 3–6 months. Wells cease natural flow and cannot sustain production even after what is considered acid fracturing without the help of artificial lift. Conventional production plots show that typical performance begins with a high initial rate for a short duration followed by a sharp decline before a stabilization period. To improve and recommend a proper hydraulic fracture design, the authors studied the effectiveness of current stimulation to develop alternative improvement procedures. Methodology The effectiveness of acid stimulation was analyzed and evaluated by using historical production for 4 years. To study the initial rates seen on these horizontal wells, a productivity-prediction tool was used to inversely compute the effective formation-permeability responsible or the observed initial production on these wells. Production data were used to inversely calculate the geometrical averaged permeability from initial field-production data assuming that the initial conditions followed a steady-state regime.

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Carpenter, Chris. "Riser Allows Live-Well Intervention With Coiled Tubing From Monohull Vessel". Journal of Petroleum Technology 75, nr 06 (1.06.2023): 49–51. http://dx.doi.org/10.2118/0623-0049-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212939, “A Proven and Versatile Coiled Tubing Live-Well Intervention Solution From a Monohull Vessel in the Norwegian Continental Shelf,” by Kjetil Austbø and Stein Kristian Andersen, Equinor, and John Stuker, SPE, SLB, et al. The paper has not been peer reviewed. _ The complete paper describes the use of a riser for coiled tubing (CT) operations from a monohull vessel already performing riserless well interventions (RLWI). The project was developed by the operator, an intervention-vessel company, and several service providers. The solution covers 200- to 500-m water depths and converts back to riserless operation after CT operations. Introduction The operator has more than 600 subsea wells globally in multiple countries and more than 550 subsea wells on the Norwegian Continental Shelf (NCS), which accounts for more than 83% of all subsea wells in the area. Successful interventions here using RLWI vessels encouraged the operator to investigate the possibilities of also performing CT operations from a vessel. The best option was found to be a strategy that included a monohull vessel that could perform both RLWI and CT operations. The analysis of operations in rough-weather conditions in the NCS showed that riser-based CT operations from such a vessel could be performed in the summer season only. Thus, the operator required a flexible solution such that the same RLWI vessel could cover both year-round RLWI and summertime riser-based CT interventions efficiently. The solution materialized when a larger vessel was engaged to expand the usable weather season and allow year-round RLWI operations. Description and Application of Equipment and Processes To enable riser-based CT intervention in the NCS, the chosen option required more equipment and interfaces than were required when performing RLWI. To conduct riser-based CT interventions in live wells, a way to handle, deploy, and tension the high-pressure riser was required, as was an interface for both wireline and CT equipment in the vessel. A system to handle live-well returns from the well also was necessary. After many engineering iterations, the RLWI vessel implemented a modular riser-handling package that could be installed and then removed when not needed. On top of the surface flow tree, a custom CT tension frame (CTTF) was developed for the CT and wireline stacks and pressure control equipment (PCE), each inside separate support frames within the CTTF. With the CTTF connected to the riser, each support frame could be skidded to the well center, eliminating the need for crane lifts while changing between wireline and CT. CT Planning Well Control and Barriers. Because of limited space on the RLWI vessel, only one dual-ram blowout preventer (BOP) would fit in the CT support-frame cartridge within the CTTF. In addition to the dual strippers, the rest of the PCE requirement considered the subsea emergency disconnect package (EDP) and lower riser package (LRP) to complete the well-control equipment. The EDP and LRP included a safety head, a production isolation valve, and a retainer valve, all capable of cutting wireline and CT.

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Carpenter, Chris. "AI-Based System Automates Textual Classification of Daily Drilling Reports". Journal of Petroleum Technology 76, nr 02 (1.02.2024): 55–57. http://dx.doi.org/10.2118/0224-0055-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32978, “Development and Implementation of an AI-Based System To Automate Textual Classification on Daily Drilling Reports,” by Stephan Perrout, Aliel F. Riente, and Guilherme S.F. Vanni, SPE, Petrobras, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. Reproduced by permission. _ Structured daily drilling reports (DDRs) are a rich source of information that allows better planning, more-accurate risk analysis, and improved key performance indicators and contracts. However, such information is originally stored in a free-text and unstructured format, which becomes difficult for efficient data mining. With the advance of artificial intelligence (AI) technologies, particularly AI language models, applying such techniques over unstructured data has become critical to digital transformation. The complete paper presents an approach for automatic DDR classification that incorporates new techniques of AI. Introduction This work addresses the complex task of automatic classification of DDRs according to a newly proposed ontology. The ontology follows a hierarchical model that classifies actions into three or four levels depending on the intervention, considering drilling, completion, and abandonment. Each event has an ontology built and reviewed by experts in oil and gas. Classifying DDR constitutes a demanding task, and effectively exploiting AI-based models represents a promising solution. This work bridges the gap by proposing a classifier based on transformers along with recurrent neural networks (RNNs) to classify reported events described in unstructured text related to drilling, completion, and abandonment interventions. A large number of DDRs was used for training and validation of the proposed classifier, yielding promising results for key processes in the company. Neural-Network Techniques Bidirectional Long Short-Term Memory. Early neural-network models are characterized by inputs of fixed length. This is a drawback when working with texts, however, because sentences vary in their number of words. To overcome such an issue and to process data sequentially, RNNs were proposed. The RNNs are characterized by a set of parameters inherent from the early models plus an internal memory (a hidden or internal state) responsible for storing the context of the sequence being processed. Long short-term memory (LSTM) is a variation of RNN proposed to mitigate two problems: Information can be easily lost when processing very long sequences, and the gradient can become quite low because of the high number of mathematical operations performed during the processing while remaining far from reaching the threshold. LSTM consists of a set of parameters called the input gate, forget gate, and output gate that control information flow through the network. This set of additional parameters helps to maintain only what is important for the internal state of the network besides controlling the output. BiLSTM is a variant of LSTM that comprises two LSTMs. One processes texts from left to right, and the second one processes texts from right to left. This feature allows “future” elements to be part of the model’s decision process for “past” elements. The final classification is the combination of the output of both LSTMs.

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Carpenter, Chris. "CO2 Injectivity Test Proves Concept of CCUS Field Development". Journal of Petroleum Technology 76, nr 02 (1.02.2024): 63–65. http://dx.doi.org/10.2118/0224-0063-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.

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Faridi, Mohammad Rishad, Arun Patni, Ryhan Ebad i Neelima Patni. "Wax and wane: a case study of Flying Colours". Emerald Emerging Markets Case Studies 12, nr 2 (5.04.2022): 1–40. http://dx.doi.org/10.1108/eemcs-01-2021-0015.

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Learning outcomes At the end of the case study discussion, students will able to state the importance of outsourcing with comparing pros and cons in business decision-making; review the value bestowed to the community in using sustainable raw material while at the same time conserving the ancient style of artwork particular to the area; discuss the utility of the products manufactured by “Flying Colours,” especially for the lockdown period which was because of the pandemic; and demonstrate and interpret the use of shark and mosquito bite matrix. Case overview/synopsis Arun Kumar Patni, 47, and his wife Neelima Patni, 43, are co-founders of Flying Colours, a start-up company based in Jaipur, in the state of Rajasthan, India. Their enterprise was engaged in the manufacturing and marketing of bird products and accessories, including bird feeders, bird houses, earthen water bowls, etc. In July 2020, post-lockdown, they were desperate to hire carpenters to restart their factory. However, COVID-19 posed a serious challenge, making it very difficult to replace their skilled carpenters, who had returned to their native places and had not come back. This disrupted production and order fulfilment. Keeping this situation in perspective in anticipation of the continuing pandemic crisis, Neelima was in favour of outsourcing basic production and designing the birdfeed decoration and artwork in-house. Meanwhile, Arun instead favoured continuing full in-house production as before, by hiring replacement carpenters. Yet for an in-house full-scale production, procuring raw material was a difficult task because of the lockdown. The situation had earlier taken a turn for the worse when Arun had advertised an exchange marketing policy to let customers return their old bird feeders for a 20% discount on a new one. This campaign was a huge success and resulted in a sales spike but unfortunately it caused a huge stock of returned products in their warehouse. Arun initially planned to repair and resell them as refurbished products. It now seemed impossible, because local carpenters demanded higher labour charges than the regular carpenters did. Flying Colours had provided skills workshops and hired external trainers to train unskilled carpenters prior to lockdown, so now all the training investment was in vain. Cash liquidity, sales, marketing, etc. were almost at a standstill. Complexity academic level This case particularly focuses on undergraduate-level students pursuing business or commerce programs, especially those studying core course: Entrepreneurial Strategic Management. Supplementary materials Teaching notes are available for educators only. Subject code CSS 3: Entrepreneurship.

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Stokes, Veronica. "A History of the Carpenters’ Company. By Jasper Ridley. 230mm. Pp. 223, 86 ills. London: Carpenters’ Hall, 1995. ISBN 0-906290-12-0. Price not given." Antiquaries Journal 77 (marzec 1997): 428–29. http://dx.doi.org/10.1017/s000358150007551x.

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Reed, Douglass C. "Palkehitus: uurimise, taastamise ja arenguloo selgitamise vajadused Eestis ja maailmas / Relevance of Log Crib Research, Renovation and Development in Estonia and the World". Studia Vernacula 7 (4.11.2016): 180–210. http://dx.doi.org/10.12697/sv.2016.7.180-210.

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In 1972, I was apprenticed to an elderly mountain man steeped in the traditions of log crib construction. Cyrus Paul Lewis taught me the skills of 18th and 19th century rough and finish carpentry as it pertained to folk architecture. The craft training of log construction added on top of several years experience as a modern day carpenter enabled me to build a company that restored houses and other log buildings all over the United States from 1974 to 2006. In 1978 I continued my formal education in anthropology and preservation specializing in log structures at George Washington University in Washington, D.C. Having read all the authoritative works on log buildings and compared them to what I was learning in the field, it was obvious there were many gaps in the collective body of knowledge concerning the development and dissemination of log crib structures.During a brief first trip to Europe, it was easy to see that the log crib buildings in Alpine and northern Europe in no way resembled the American log cribs erected for three centuries by the settlers arriving on the American shores and those pushing west to establish their farms and build their houses. It became clear American scholarship had a long way to go in understanding the log crib, its development, technology and dissemination throughout the world much less in America. In 2009 a quest to fill in some of the gaps was begun.After four years of intense research with field trips to Turkey, southern Europe and ranging all the way north to the Scandinavian and Baltic countries ringing the Baltic Sea two findings became very clear. First, no one person can possibly conduct the massive research needed to fully understand origins, technology and dissemination of the world's log cribs. Secondly, it was apparent, contrary to what had been declared in former publications, that Europeans did not transfer their log crib technologies intact to the eastern shores of the US. Rather only a small number of scattered details mixed with a few processes of material manufacturing and building commonly used in Europe were configured into what was to become an American log crib style almost from the first settlements.These discoveries bore witness to the fallacy of single or two person research efforts that resulted in broad, sweeping declarations of origins and disseminations concerning log crib technologies. Most authors were not familiar with the professional training needed to fully understand the hands-on traditions of building with logs and have largely missed the facts concerning the developmental history of log buildings in a specific country and the world. Far more collaborative research between the multiple disciplines and experienced master craftsmen is needed.Even in Estonia further studies are needed to determine how the dual-purpose barn-dwelling developed and where it originated. With seven centuries of multiple foreign occupations responsible for bringing in many different types of technologies form their occupiers' homelands, Estonia is a perfect research area for studying and tracking details of development within the country and tracing them back to their origins.Estonia is not the only country where a rich tradition of log construction needs further research. Further Continental and world-wide log crib studies are needed on a global basis. National surveys must be completed and all resulting data shared to a central data base and collated for developmental research to take place. This work is vital to the understanding of the origins, development and disseminations of log crib technologies throughout the world much less the US and the European Continent.The results of multiple global log crib research efforts will have far reaching effects in craft training, log crib technology training, and in reintroducing relative millennia's old technologies in a modern day world rife with toxic fixes that do not work very well in new construction. New restoration techniques of wooden buildings will be learned and culled from the research. Environmental considerations that reduce CO2 levels, green house effects and increase local community cohesiveness all will benefit from global in-depth research efforts to fill in the missing information gaps in log crib development and technologies.In order for all this research to be coordinated, collated and disseminated, a single global organization dedicated to the study of log crib development must be formed. A new organization focused solely on ferreting out log construction histories, developing techniques of restoration, forest management and timber conservation is necessary in part to provide continued introductory and higher level job training for a log crib work force. The research and training is imperative if the world is to maintain and develop additional higher paying jobs, lower taxes, maintain existing log structures, wisely use limited natural resources in an efficient manner and better living conditions for millions of people.

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Reed, Douglass C. "Palkehitus: uurimise, taastamise ja arenguloo selgitamise vajadused Eestis ja maailmas / Relevance of Log Crib Research, Renovation and Development in Estonia and the World". Studia Vernacula 7 (4.11.2016): 180–210. http://dx.doi.org/10.12697/sv.2016.7.180-210.

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In 1972, I was apprenticed to an elderly mountain man steeped in the traditions of log crib construction. Cyrus Paul Lewis taught me the skills of 18th and 19th century rough and finish carpentry as it pertained to folk architecture. The craft training of log construction added on top of several years experience as a modern day carpenter enabled me to build a company that restored houses and other log buildings all over the United States from 1974 to 2006. In 1978 I continued my formal education in anthropology and preservation specializing in log structures at George Washington University in Washington, D.C. Having read all the authoritative works on log buildings and compared them to what I was learning in the field, it was obvious there were many gaps in the collective body of knowledge concerning the development and dissemination of log crib structures.During a brief first trip to Europe, it was easy to see that the log crib buildings in Alpine and northern Europe in no way resembled the American log cribs erected for three centuries by the settlers arriving on the American shores and those pushing west to establish their farms and build their houses. It became clear American scholarship had a long way to go in understanding the log crib, its development, technology and dissemination throughout the world much less in America. In 2009 a quest to fill in some of the gaps was begun.After four years of intense research with field trips to Turkey, southern Europe and ranging all the way north to the Scandinavian and Baltic countries ringing the Baltic Sea two findings became very clear. First, no one person can possibly conduct the massive research needed to fully understand origins, technology and dissemination of the world's log cribs. Secondly, it was apparent, contrary to what had been declared in former publications, that Europeans did not transfer their log crib technologies intact to the eastern shores of the US. Rather only a small number of scattered details mixed with a few processes of material manufacturing and building commonly used in Europe were configured into what was to become an American log crib style almost from the first settlements.These discoveries bore witness to the fallacy of single or two person research efforts that resulted in broad, sweeping declarations of origins and disseminations concerning log crib technologies. Most authors were not familiar with the professional training needed to fully understand the hands-on traditions of building with logs and have largely missed the facts concerning the developmental history of log buildings in a specific country and the world. Far more collaborative research between the multiple disciplines and experienced master craftsmen is needed.Even in Estonia further studies are needed to determine how the dual-purpose barn-dwelling developed and where it originated. With seven centuries of multiple foreign occupations responsible for bringing in many different types of technologies form their occupiers' homelands, Estonia is a perfect research area for studying and tracking details of development within the country and tracing them back to their origins.Estonia is not the only country where a rich tradition of log construction needs further research. Further Continental and world-wide log crib studies are needed on a global basis. National surveys must be completed and all resulting data shared to a central data base and collated for developmental research to take place. This work is vital to the understanding of the origins, development and disseminations of log crib technologies throughout the world much less the US and the European Continent.The results of multiple global log crib research efforts will have far reaching effects in craft training, log crib technology training, and in reintroducing relative millennia's old technologies in a modern day world rife with toxic fixes that do not work very well in new construction. New restoration techniques of wooden buildings will be learned and culled from the research. Environmental considerations that reduce CO2 levels, green house effects and increase local community cohesiveness all will benefit from global in-depth research efforts to fill in the missing information gaps in log crib development and technologies.In order for all this research to be coordinated, collated and disseminated, a single global organization dedicated to the study of log crib development must be formed. A new organization focused solely on ferreting out log construction histories, developing techniques of restoration, forest management and timber conservation is necessary in part to provide continued introductory and higher level job training for a log crib work force. The research and training is imperative if the world is to maintain and develop additional higher paying jobs, lower taxes, maintain existing log structures, wisely use limited natural resources in an efficient manner and better living conditions for millions of people.

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Carpenter, Chris. "Innovation, Integration Enable Success in Guyana-Suriname Basin". Journal of Petroleum Technology 75, nr 02 (1.02.2023): 92–94. http://dx.doi.org/10.2118/0223-0092-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30946, “Innovation and Integration: Exploration History, ExxonMobil, and the Guyana-Suriname Basin,” by Audrey L. Varga, Matthew R. Chandler, and Worth B. Cotton, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ Exploration in the Guyana-Suriname Basin has been a decades-long endeavor, including technical challenges and a lengthy history of drilling with no offshore success before the 2015 Liza discovery. The collection of extensive seismic data has been leveraged to enable successful exploration of multiple play types across the basin. Further data collection has enabled the operator to adopt interpretation techniques that are applied across the entire basin to characterize and understand the subsurface better. Historical Context The first wells drilled in the Guyana-Suriname Basin were onshore; the Rose Hall well in Guyana in 1941 first found oil shows. Rumors of oil in the region, and hopes that the prolific hydrocarbon systems present in Venezuela extended into Guyana and Suriname, led geologists from the Standard Oil Company to conduct initial reconnaissance and seismic and geochemical studies. Despite hints—in retrospect—of a favorable basin configuration and hydrocarbon presence, the decision was made to discontinue exploration activities. Through the 1950s and early 1960s, the region saw relatively low levels of activity. In 1960, the first well was drilled offshore Guyana, and, in 1964, the first offshore well was drilled in Suriname; both were dry. In 1965, the Geological and Mining Service of Suriname found heavy oil near the present-day Calcutta Field. This led to the discovery of the Calcutta, Tambaredjo, and Weg naar Zee heavy-oil accumulations, but only a thin reservoir and heavy oil were encountered. In 1975, Esso participated in the North Coronie-1 well in Suriname. The well found oil and gas shows, confirming the presence of immature but rich source rock that was age-equivalent to the prolific La Luna source in Venezuela. A reconnaissance 2D seismic program followed, and, in 1978, Esso drilled the first deepwater well at Demerara A2-1. This well also was dry but did find high-quality, immature source rock and weak oil and gas shows. After another disappointing well at FG-1 in French Guyana in 1978, Esso ultimately relinquished its licenses but noted the presence of excellent-quality source rocks and reservoirs. The onshore Tambaredjo field, discovered in the 1960s, did not start production until 1982. All in all, before the Liza discovery, more than 300 wells were drilled in the basin, with more than 200 of these dry. Of these, all 60 offshore wells were dry. Why, then, did exploration continue? Data Evolution In the mid- to late-1990s, the Guyana deepwater acreage was completely open. The data available to the operator’s geoscientists consisted of one or two seismic lines, approximately four offshore wells, and a Suriname onshore oil sample. At that time, a major change in global coverage and quality of satellite free-air gravity data occurred with the declassification of US military data. An internal project by the operator merged the Sandwell and Smith free-air gravity grid, available in the public domain, with Getech onshore Bouguer gravity grids to create a global gravity compilation. The operator’s researchers recognized the applicability of these data as a key technology enabler to update plate tectonic models and genetic basin analysis.

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Carpenter, Chris. "Saudi Arabia Case Study Illustrates Road to Zero Routine Gas Flaring". Journal of Petroleum Technology 75, nr 04 (1.04.2023): 55–57. http://dx.doi.org/10.2118/0423-0055-jpt.

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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21182, “The Road to Zero Routine Gas Flaring: A Case Study From Saudi Arabia,” by Majed Alsuwailem, KAPSARC. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ The complete paper discusses Saudi Arabia’s progress in gas flaring, the measures the government has taken, and how operators have adapted. It also identifies many lessons learned and technological solutions that could be scaled up on a national or a corporate level to reduce gas flaring to achieve zero routine flaring targets, especially in cases where the state owns hydrocarbon assets and leases them to private operators. History of Gas Flaring in Saudi Arabia Following the discovery in 1948 of Ghawar, Saudi Arabia’s largest oil field, oil production in the country increased and more associated gas was produced and flared. The national oil company, Saudi Aramco, had no interest in capturing gas produced from its oil operations. No local or regional market for it existed, and exporting the gas would have required substantial infrastructure investments. This coincided with periods of low crude oil prices that made gas projects uneconomical. However, as the 1960s and ’70s passed, gas came to be increasingly regarded as an essential part of a broader attempt to diversify the Saudi economy. This, in return, allowed the creation of jobs in new frontiers, including the refining and petrochemical industries. In the early 1970s, the Saudi Ministry of Petroleum and Minerals contracted the Texas Eastern Corporation to conduct a technical and economic feasibility study. It evaluated the benefits of establishing a massive refining and petrochemical industry in the city of Jubail on the Arabian Gulf and Yanbu on the Red Sea, with gas as an important feedstock. The study required major capital expenditures on midstream oil operations. Saudi Aramco, on the other hand, proposed exploiting associated gas to generate electricity. Because the price of oil did not exceed $3/bbl before the 1970s, the Saudi government opted for the first option. Saudi Aramco, however, only foresaw an opportunity in this development if the government contributed major capital to the midstream, resulting in a positive outcome for both the stakeholders and the operator, which turned out to be the case. Master Gas System (MGS) The government gave Saudi Aramco a contract to establish the $12 billion MGS to capture, process, and use gas as fuel and feedstock for the petrochemical plants. Most of this project was paid for by the government. By the fall of 1982, the key components of the MGS (gas-gathering and -processing facilities and pipelines) were fully operational. The MGS saved 4.2 billion scf of gas from being flared, which prevented 80 million tonnes of carbon dioxide from being emitted into the atmosphere annually. Over time, the MGS has been expanded as more oil and nonassociated gas fields have been placed onstream and as demand has risen for dry gas in the power sector. By 2018, the MGS had gathered almost 3.5 trillion ft3/yr and is one of the world’s largest single hydrocarbon networks. It includes 4,000 km of pipelines, 50 gas/oil separation plants (GOSPs), seven gas plants, and two natural gas/liquid units.

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