Journal of Petroleum Technology最新文献

{"title":"A Grand Challenge: Net-Zero Operations—Changing the Definition of “Business as Usual”","authors":"Eliz Ozdemir, Justine Roure","doi":"10.2118/0524-0050-jpt","DOIUrl":"https://doi.org/10.2118/0524-0050-jpt","url":null,"abstract":"\u0000 \u0000 This is the second of a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas.\u0000 Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; improving recovery from tight/shale resources; net-zero operations; carbon capture, storage, and utilization; digital transformation; and education and advocacy.\u0000 The first article, “An SPE Grand Challenge Update on Geothermal Energy,” was published in April 2024.\u0000 \u0000 \u0000 \u0000 At COP28, more than 50 oil and gas companies, many of them national companies, took a historic step toward decarbonization by launching the Oil & Gas Decarbonization Charter. The charter represents significant short- and long-term ambitions to reduce emissions, including net-zero operations by 2050 at the latest.\u0000 This article explores the importance of this effort, the opportunities available to the industry to reduce its Scope 1 and 2 emissions, and the key technologies needed to achieve the net-zero goal.\u0000 \u0000 \u0000 \u0000 According to the latest data from the International Energy Agency (IEA), the production, transport, and processing of oil and gas resulted in 5.1 GtCO2e in 2022. These emissions stem from the production and delivery of oil and gas and the combustion of fossil fuel necessary for operations on-site (Scope 1), and the import of electricity from external sources consumed in oil and gas facilities (Scope 2).\u0000 These Scope 1 and 2 emissions represent just under 15% of global energy-related greenhouse gas (GHG) emissions. This is a sizable contribution, nearly equivalent to all energy-related GHG emissions from road transport, highlighting the relative scale of the opportunities associated with implementing operational changes in the industry. The faster and deeper these emissions reductions are, the more significant the impact will be.\u0000 \u0000 \u0000 \u0000 To understand the various paths to net zero an oil and gas company can follow, it is critical to map the sector’s sources of emissions throughout the value chain. It is generally recognized that around 60% of an integrated company’s emissions emanate from upstream operations, predominantly from onshore assets. Refining and distribution are the second main contributors, but of a smaller order of magnitude, notably because of significant efforts already made by companies to reduce emissions from their refining assets and levers of decarbonization potentially easier to implement.\u0000 However, emissions volumes and intensities differ significantly across regions, countries, and asset types. An asset operating in the Canadian oil sands region will have a very different emissions profile compared to an offshore platform in Western African countries. These differing profiles also call for tailored emission-reduction approaches. This means decarbonization studies must be carried out at the asset level, allowing operator","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"51 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141034165","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Resin-Cement Blend Enhances Wellbore Integrity","authors":"C. Carpenter","doi":"10.2118/0524-0109-jpt","DOIUrl":"https://doi.org/10.2118/0524-0109-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213763, “Use of Innovative Resin-Cement Blend To Enhance Wellbore Integrity,” by Wajid Ali, Faisal A. Al-Turki, and Athman Abbas, SPE, TAQA Well Services, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 A major challenge occasionally faced during a well’s life cycle is the buildup of sustained casing pressure (SCP). Compromised cement-sheath integrity is one of the primary reasons for such a pressure buildup. Meeting this challenge requires development of an isolation material that can enhance the mechanical properties of cement. This paper presents the laboratory testing and application of a resin-cement system in a scenario where potential high-pressure influx was expected across a water-bearing formation. The resin-cement system was designed to be placed as a tail slurry to provide enhanced mechanical properties compared with a conventional slurry.\u0000 \u0000 \u0000 \u0000 The objectives of this study were to investigate the use of new systems at different densities with epoxy resin as an additive and to demonstrate value added in terms of improved mechanical properties and bonding.\u0000 The resin used in this study is diglycidylether of bisphenol-F, a linear epoxy resin formed by reacting bisphenol-F with a suitable amount of epichlorohydrin and hydroxide. Amines are used as curing agents for epoxy resins. The curing mechanism is a step-growth polymerization. The curing is observed initially by an increase in viscosity and then by hardening. The final product’sproperties, in terms of compressive strength and viscosity, also are affected by the type and concentration of the amine. Aliphatic amines produce more-flexible types of epoxy resins compared with aromatic amine curing agents. Aromatic amines will produce a stronger, harder epoxy resin.\u0000 \u0000 \u0000 \u0000 Cement Slurry Preparation and Testing.\u0000 The cement slurry was formulated and mixed with a maximum speed of 12,000 rev/min for 15 seconds and then at 4,000 rev/min for 35 seconds. To condition the cement slurry, an atmospheric consistometer was used. A viscometer was used to measure rheological properties. Thickening time tests also were conducted.\u0000 Fluid-loss measurements (dynamic and static) were performed on the prepared cement slurry. Dynamic fluid loss can affect rheology and thickening time of cement slurries. Static fluid loss can result in reduction in cement slurry and allow formation fluids to enter the cement slurry.\u0000 Separation of water is observed when a cement slurry is allowed to stand for a period before it sets. To determine the extent of water separation, a free water test was performed to determine the extent of water separation. The test was conducted by allowing cement slurry to stand in a 250-mL graduated cylinder for 2 hours.\u0000 The cement slurry was poured into a cylindrical cell and lowered into a curing chamber. While maintaining pressures and temperatures, the cement slurry was cured up to 30","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"97 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141037621","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geopolymer Implemented in Primary Casing Cementing","authors":"C. Carpenter","doi":"10.2118/0524-0105-jpt","DOIUrl":"https://doi.org/10.2118/0524-0105-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32218, “First Global Implementation of Geopolymer in Primary Casing Cementing,” by Mark Meade, SPE, Yeukayi Nenjerama, SPE, and Chris Parton, SPE, SLB, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference.\u0000 \u0000 \u0000 \u0000 Portland cements are integral components in the oilfield well-construction process; however, the confluence of various business drivers have created the need to find sustainable alternative materials. The complete paper presents the evaluation of geopolymer cementing for use in oil and gas wells, specifically the primary cementing of liner strings in the Permian Basin. Geopolymer cementing offers a unique opportunity for the oilfield industry to decrease CO2 emissions related to well construction and reduce dependence on the constrained supply of Portland cements.\u0000 \u0000 \u0000 \u0000 Manufacturing Portland cement emits approximately 1 ton of CO2 for every ton of cement produced. Additionally, the manufacturing of Portland cement is a complex process requiring specialized equipment. Thus, during spikes in demand of Portland cement, the supply of cement cannot be rapidly increased to meet demand.\u0000 Geopolymers are slurries that set to become a hard, durable solid that can withstand stresses and strains and are resistant to corrosion. Moreover, geopolymers can be made from a broad range of aluminosilicate raw materials sourced from waste products from other industries, mined materials, and biowaste. The low manufacturing and processing requirements reduce the carbon footprint of geopolymers to a fraction of that of manufacturing Portland cement.\u0000 Whereas Portland cement chemistry is driven by hydration of calcium aluminates and calcium silicates, geopolymer chemistry is based on the polymerization of aluminosilicates initiated by activators. The creation of geopolymers starts with dissolution of the aluminosilicate raw material into monomers by an increase in the pH of the fluid from the activator. Then, the activator provides a site for covalently bonded chains to form, and these chains undergo polycondensation to form the set 3D network of polymers. Implementation of this new material with such a different chemistry into the complex oilfield-construction process presents challenges that must be overcome.\u0000 \u0000 \u0000 \u0000 Existing geopolymer formulations typically are characterized as either two-step or one-step geopolymers. In two-step geopolymers, the activators are added into the mix fluid, whereas, in one-step geopolymers, the activators are dry blended with the aluminosilicate source. Implementation of two-step geopolymers would come with operational and logistical constraints impairing their scalability, along with increased service quality and health, safety, and environmental (HSE) risks. On the other hand, common existing one-step geopolymers are formulated with activator types that dissolve rapidly and disperse in th","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"104 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141037579","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Digital Twin Approach Integrates Existing Facilities, Proposed Developments","authors":"C. Carpenter","doi":"10.2118/0524-0089-jpt","DOIUrl":"https://doi.org/10.2118/0524-0089-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215074, “Digital Twin for Development and Subsurface Integration: A Window Into the Future,” by Thomas K.G. Gan, Elizabeth Sumadh, and Bhaminie Sagram, Shell. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The digital twin (DT) approach provides a virtual and digital representation of existing assets, spanning everything from onshore facilities to offshore platforms, pipelines, and subsurface data, all in one location. It has been used for the operator’s flagship Manatee project to develop three stacked reservoirs offshore Trinidad and Tobago. The DT was used to identify design modifications required at this onshore site and visualize proposed offshore assets. It integrates existing facilities and new design data, including site survey, subsurface, and well data to optimize well planning.\u0000 \u0000 \u0000 \u0000 The Manatee field lies within the East Coast Marine Area of Trinidad in approximately 92 m of water and consists of stacked reservoirs of clean and thin-bed unconsolidated sands. Production from these wells is expected to be processed through a new offshore platform and transported by the new pipeline to the Beachfield onshore facility. For a feasibility study and concept-selection stages, the DT platform played a crucial factor in visualizing and contextualizing development options and allowed front-end engineering contractors and operator teams to collaborate across multiple countries and inspect the location virtually. All engineering drawings, maps, design documents, and 3D models were powered by the DT platform.\u0000 \u0000 \u0000 \u0000 Traditionally, digital collaboration is performed through data and model export from different technical applications and results presented in slides and reporting documents. For oil and gas capital projects, typically 3–6 years elapse from feasibility stage to execution, deepening the issues caused by faulty corporate memory retention, staff movement, and project handover from different internal organizations.\u0000 Manatee project teams were based in various locations in Trinidad, the US, the UK, the Netherlands, and India, thereby increasing the likelihood of error by using multiple sources of data. Furthermore, effective collaboration without a single source of truth of data can be an obstacle. Given that multiple software was used for model building, development-well planning, and satellite imagery, an inability exists to view 2D and 3D imagery of onshore and offshore facilities with the subsea and subsurface in one place. Furthermore, between 2020 and 2022, the COVID-19 pandemic led to imposed restrictions and limitations placed on site visits. In such scenarios, drone images and video data can prove useful to access facilities remotely. These challenges needed to be addressed by access to a centralized platform that collected, stored, and provided virtual representations to ensure continuous monitoring and efficient decision-making.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"154 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141028506","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Process Reduces Carbon Emissions From Natural Gas Compression and Production","authors":"C. Carpenter","doi":"10.2118/0424-0070-jpt","DOIUrl":"https://doi.org/10.2118/0424-0070-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214974,“New Technology Reduces Carbon Emissions From Natural Gas Compression and Production Facilities,” by John Guoynes, SPE, David Stiles, SPE, and Cory Vail, Axip Energy Services, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 A chemical-free process has been developed to capture exhaust from natural gas drive compressors and supporting gas-fueled production equipment while featuring a small footprint. The process separates CO2 and nitrogen from exhaust, allowing the CO2 to be discharged at high pressure for transport, sequestration, or enhanced oil recovery.\u0000 \u0000 \u0000 \u0000 Over 50,000 compressors move natural gas in North America. Most are driven by either internal combustion engines or turbines. These compressors produce am estimate of more than 30 million tonnes of CO2 equivalent yearly, according to the US Environmental Protection Agency’s Greenhouse Gas (GHG) Reporting Program.\u0000 The significance of GHG reduction policies has heightened with the passing of the Inflation Reduction Act, which provides support for companies investing in future carbon capture use and storage, along with methane reduction.\u0000 \u0000 \u0000 \u0000 Modeling and analysis of an exhaust-gas carbon capture system, and the design and optimization of a supercritical CO2 (sCO2) waste-heat-recovery power cycle, was performed. This cycle was chosen for its high efficiency and relatively compact design compared with competitive waste-heat-recovery technologies. The preliminary process-flow diagram was provided based on conditions for 30,000-hp large reciprocating gas engines. Several process configurations were investigated; these iterations are detailed in the complete paper.\u0000 A summary of this development shows that Iterations 1 through 3 showed improvements in power through improving the sCO2 power-cycle efficiency. However, this came at the increase in high-pressure sCO2 components. A simplification of components returned the sCO2 cycle to a single cascaded cycle in Iterations 4 through 5. Temperature selection in the sCO2 cycle also improved its efficiency. Moving to Iteration 4 improved the system power requirement by 20.7%. Iteration 5 showed moderately reduced performance over Iteration 4. This was the result of shifting more duty to the ammonia chillers and a moderate worsening of performance in the gas compressor. Iteration 5 did not improve the power requirement of the system. Ultimately, Iteration 4 was the most-efficient cycle evaluated with the overall lowest power requirement.\u0000 \u0000 \u0000 \u0000 The system developed captures exhaust from compression and other internal combustion equipment commonly used in gas transmission, oil and gas production, and midstream applications. The system works with a chemical-free, cryogenic design with a small modular footprint to capture large volumes of exhaust gas at atmospheric pressure. This technology separates CO2 and nitrogen, generates enough power f","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140784960","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Equinor Leads Project To Turn Ubiquitous Drill Cuttings Into Precious PVT Samples","authors":"Trent Jacobs","doi":"10.2118/0424-0032-jpt","DOIUrl":"https://doi.org/10.2118/0424-0032-jpt","url":null,"abstract":"They were told it wouldn’t work.\u0000 But in a new study, experts at Equinor and Applied Petroleum Technology (APT) suggest they are on the brink of using contaminated drill cuttings to predict critical reservoir fluid properties.\u0000 The two Norwegian firms believe their project will soon make it possible to treat cuttings, collected from each well, as if they were pressure/volume/temperature (PVT) samples, which are collected from a significantly smaller share of wells due to the risks and high cost of doing so.\u0000 Since its inception in 1972, Equinor has drilled over 5,000 offshore wells, from which just over 2,000 PVT samples have been gathered.\u0000 Given that only two or three good samples are taken from most wells—almost always exploration wells—a significant data gap exists for the remainder, most of which are the subsequent development wells. And each year, Equinor drills around 20 to 25 new wells, mostly near existing platforms.\u0000 If oil and gas firms could obtain PVT-like results from cuttings alone, they would presumably gain more precise guidance on where to place new wells along with insights on facility/topside design, reservoir management, and eventually on the plugging and abandonment phase.\u0000 The big obstacle Equinor and APT are trying to surmount centers on how rock cuttings are soaked in oil-based muds (OBMs) as they circulate up the wellbore before being collected from a shale shaker. The oil ends up masking the reservoir’s hydrocarbons, rendering traditional geochemistry methods ineffective.\u0000 What Equinor has shown in its study is that problem can be circumvented to obtain reliable estimates of API gravity and viscosity, two defining aspects of reservoir fluid quality and flow potential. Several more outputs are in the works.\u0000 Tao Yang, an industry-recognized reservoir expert and chief professional at Equinor, said when he spoke with geochemists in the company about the project nearly 2 years ago, they were decidedly dubious.\u0000 “They gave us a warning at the beginning and said that this was a very difficult area, that the cuttings were too dirty, and that we probably wouldn’t get anything out of them,” he said.\u0000 But what few in the upstream industry knew at the time is that there existed a technology that can overcome the contamination issue—and it has been around for decades. Invented in the 1960s, gel permeation chromatography (GPC) coupled with ultraviolet (UV) absorbance detection, or simply GPC-UV, is used primarily by the chemicals sector for polymer analysis.\u0000 The GPC aspect separates molecules based on their size as they flow through a gel-filled column. The smaller molecules take the longest to pass through while the larger molecules move more rapidly—the opposite of how most geochemistry assays work.\u0000 As the molecules move down the column, they are exposed to UV light. Depending on their chemical structure, each molecule will absorb light at varying intensities which in turn can be measured and used to detect the presence of vario","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"88 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140768078","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Lean Gas-Flare-Tip Technology Reduces Emissions in the Gulf of Thailand","authors":"C. Carpenter","doi":"10.2118/0424-0064-jpt","DOIUrl":"https://doi.org/10.2118/0424-0064-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216098, “Revolutionizing Sustainability: Achieving Net-Zero Emissions With Lean Gas-Flare-Tip Technology Breakthrough in the Gulf of Thailand,” by Nunthachai Amarutanon, Boonyakorn Assavanives, and Kantkanit Watanakun, PTTEP, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 In the complete paper, the authors describe an extremely low-BTU (ELBTU) flare-tip technology designed to help the oil and gas industry achieve net-zero targets. The operator embarked on a joint research and development project to address the limitations of high-heating-value requirements by designing the technology. The prototype was proved to successfully combust lower-heating-value flare gas, significantly outperforming existing technologies.\u0000 \u0000 \u0000 \u0000 The joint research and development project began work in 2018. The development of the described technology began with a literature survey on lean-gas-combustion theory. The project included multiple iterations of prototype design, simulation, and testing, with various parameter adjustments to optimize performance while considering a thorough range of combustion criteria. The design was studied through computational fluid dynamics simulation and tested to determine its operating envelope. Confidence in the performance and mechanical integrity of the final design has been proved by a series of prototype tests.\u0000 \u0000 \u0000 \u0000 Requirements and general functions that had to be achieved by the technology, all of which are detailed in the complete paper, included the following:\u0000 - Maintain flame stability\u0000 - Minimize burnback\u0000 - Minimize flame pulldown\u0000 - Ensure mechanical integrity\u0000 The design of the ELBTU flare tip, shown in Fig. 1, includes an assist fire around the tip-perimeter discharge and spokes that penetrate the flare-gas discharge. The assist fire is designed as a supplementary gas burner where assist gas and assist air are delivered. Jet pumps are used to supply assist air to the assist gas burner, minimizing the line size for the assist air. With this design, assist gas and assist air are well-mixed, producing stable combustion and providing heat to the flare gas. A top hat was introduced to mitigate wind impact, retard the mixing of ambient air, and increase the time the flare gas remains at elevated temperatures. These benefits allow combustion of the assist gas and subsequent mixing of combustion radicals with the flare gas without the involvement of wind. Two of the major components, the assist fire ring and the spokes, were borrowed from existing tip designs that have proved reliable over decades of operation.\u0000 \u0000 \u0000 \u0000 The prototype test investigated flare-tip performance by varying vent-gas low heating value (LHV), vent-gas exit velocity, assist-air flow rate, and assist-gas flow rate (related to heat release) with and without a wind generator and with and without the top hat. The wind generator was an upgrade to the test fa","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"245 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140782686","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study Identifies Opportunities for Intervention Improvement With Collaborative Workflows","authors":"C. Carpenter","doi":"10.2118/0424-0075-jpt","DOIUrl":"https://doi.org/10.2118/0424-0075-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212922, “The Intervention Opportunity: Why the Industry Does Not Do More and How New Collaborative Workflows With Aligned Outcomes Can Change This,” by Matthew E. Billingham, SPE, SLB; Fraser J. Proud, North Sea Transition Authority; and Pierre Ramondenc, SPE, SLB. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The authors write that their analysis presented in the complete paper challenges the typical way interventions have been planned and executed, both from an operational and commercial basis, and examines where room exists for significant improvement. The paper examines the case for performing interventions and aims to identify opportunities for both financial and net-zero-goal achievement. By appreciating the issues operators face when justifying and designing intervention activity, challenges can thus be addressed by proper alignment for the best outcome.\u0000 \u0000 \u0000 \u0000 Downhole issues can be broken into two main categories: reservoir-based bottlenecks, and well-integrity and completion hardware issues. Problems categorized as reservoir-based can manifest either in the formation or in the wellbore. For instance, scaling and sand production are processes that originate from the reservoir but must be dealt with at least partially in the wellbore. The same is true for downhole flow-assurance challenges, which often find their root cause in the reservoir.\u0000 \u0000 \u0000 \u0000 In the UK, operators complete an annual stewardship survey (also known as the UKSS) for which a large amount of data is collected, especially around wells. The average production added from many subsea intervention jobs is significant, with reperforations, for example, adding approximately 120,000 BOE/yr per intervention, a more than 300-BOEPD uplift. Clearly, opportunities exist to increase production in the UK Continental Shelf (UKCS). The question becomes whether the investment in intervention is economical.\u0000 Not all operators use well interventions to their maximum potential. A large variance exists in the number of jobs an operator completes; the operators seeing the most production added generally are the ones performing the most interventions.\u0000 Many operators may be capital-constrained and, thus, cannot invest in more well intervention. However, it is clear that operators that do invest consistently see good value returns.\u0000 \u0000 \u0000 \u0000 Platform/Wellsite Access. A major obstacle to performing interventions is the logistical bottleneck created by additional persons on board (POB) and deck-space limitations. This applies to operations on land as well, where lack of facilities, especially in remote locations, may cause similar bottlenecks.\u0000 Asset Mindset. Another difficulty is sometimes referred to as the “asset mindset,” whereby the asset-management team might regard interventions as a high-risk operation, which jeopardizes the existing production base as opposed to gaining a potential uplift. The ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"762 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140782367","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study Details Evolution of Operator’s Completions in Vaca Muerta","authors":"C. Carpenter","doi":"10.2118/0424-0081-jpt","DOIUrl":"https://doi.org/10.2118/0424-0081-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212574, “From Exploration to Development: The Completion Evolution in Vaca Muerta,” by Juan C. Bonapace, SPE, Luis A. Riolfo, and Rodrigo Zrain, Total, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Operators in the Neuquén Basin have developed Vaca Muerta with different results. In the case of the operator whose work is featured in the complete paper, vertical exploratory wells almost 10 years ago have given way to a current development phase with multihorizontal well pads targeting different landings. The authors discuss how the operator has become more efficient and cost-effective by increasing production and reducing well-delivery-cycle time, while fostering the long-term sustainability of the project by reducing the environmental impact of operations.\u0000 \u0000 \u0000 \u0000 The authors focus on the operator’s Field A, where the most progress has been made over the years. The exploratory and appraisal phases of the development are detailed in the complete paper.\u0000 Pilot Phase.\u0000 The primary goal for this phase was to validate the productivity of two previously identified landing zones, namely Zones B and D. The wells were located near the vertical wells.\u0000 Completion. The campaign program accounted for 12 drilled horizontal wells, only 10 of which were completed (two wells were lost because of drilling and casing-integrity issues). Well lateral length ranged between 1000 and 1500 m. The final well architecture was composed of three strings: a 13⅜-in. surface casing, a 9⅝-in. intermediate casing, and a 5½-in. production casing.\u0000 The completion technique applied was plug-and-perf (PnP) and considered an average stage length of 100 m. Two base designs were defined for each landing zone according to the results obtained in the vertical exploratory wells.\u0000 An initial sensitivity trial was completed in Zone B, with two different treatment sizes, base and alternative, designed to evaluate the effect on cost and production performance. The results showed a lower production for the wells with the alternative treatment.\u0000 Operational Issues. Operational problems included casing restriction, detected only once in a well in Zone D during plug drillout operations; and well interference, in that one well presented a change in production during the flowback period on a new neighboring well. This was the result of reduced spacing because of drilling conditions between the new well and the pre-existing one.\u0000 This phase showed wells in Zone B performing beyond expected production, while those in Zone D underperformed.\u0000 Development Phase I.\u0000 It was decided to locate all wells of this phase on the east side of the pilot in the dry-gas window. The main driver for this decision was expected lower CO2 production in this region, based on observations from appraisal wells.\u0000 Completion. Initial development considered 20 horizontal wells, mainly targeting Zone B. Two additional target","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"57 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140759317","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Hybrid Approach Proves Effective in Multiwell Forecasting in Unconventionals","authors":"C. Carpenter","doi":"10.2118/0424-0103-jpt","DOIUrl":"https://doi.org/10.2118/0424-0103-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3855422, “RGNet for Multiwell Forecasting in Unconventional Reservoirs,” by Zhenyu Guo, SPE, and Sathish Sankaran, SPE, Xecta Digital Labs, and Ying Li, The University of Tulsa. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The aim of the complete paper is to propose a hybrid approach that combines physics with data-driven approaches for efficient and accurate forecasting of the performance of unconventional wells under codevelopment. The method the authors propose is the reservoir graph network (RGNet) model. By reducing system complexity while maintaining fundamental physics, the model provides an efficient and accurate way to model, history-match, and predict unconventional wells. Compared with a full-physics model that takes from hours to days to run, the described model only takes from seconds to minutes.\u0000 \u0000 \u0000 \u0000 Developing unconventional reservoirs is a complex process involving well targeting, timing, spacing, and completion design for horizontal wells with hydraulic fractures. Among commonly used methods, decline curve analysis (DCA) can execute quick well-performance analysis without considering the complex physics in unconventional reservoirs piece by piece. The convenient aspect of DCA is that practitioners can obtain forecast results quickly by providing historical production data. However, because DCA has some strong assumptions on operational conditions and does not incorporate the key physics of the flow, it may fail to predict accurately in many situations.\u0000 As a simple, fast tool for analyzing the capacity of a reservoir, rate transient analysis (RTA) has been used to model and forecast unconventional wells. Both pressure and rate data are considered to generate solutions that are more credible than those generated by DCA, where only rate information is used. The drawback of RTA is related to significant assumptions used to derive analytical solutions (e.g., homogeneous reservoir and simple planar fractures with uniform properties). Moreover, it is not an easy task to acquire some of the information required by RTA.\u0000 Full-physics reservoir simulation models are used as the most-rigorous approach to understand dynamics of unconventional reservoirs because they allow for different complexities for modeling unconventionals. However, because it takes tremendous effort for information gathering, geological/fracture modeling, and history matching, applying this approach to large-scale reservoirs is not tractable.\u0000 Based on the idea of diffusive time of flight (DTOF), the RGNet model was developed for reservoir modeling, history matching, forecasting, and optimization. It can model multiple wells with communications.\u0000 In this work, the authors incorporate pressure dependency of pore volumes and transmissibility into RGNet while modeling unconventional reservoirs.\u0000 \u0000 \u0000 \u0000 The basic idea of the described model comes from the DTOF transforma","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"95 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140789520","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}