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Collaborating Authors
Production Chemistry, Metallurgy and Biology
Novel Eco-Friendly Kinetic Hydrate Inhibitors
Xu, Kui (Baker Hughes Company) | Stewart-Ayala, Jonathan (Baker Hughes Company) | Jackson, Steve (Baker Hughes Company) | Hutchinson, Benton (Baker Hughes Company) | Sanders, Christina (Baker Hughes Company) | Jakubowski, Wojciech (Baker Hughes Company) | Jardine, Joanne (Baker Hughes Company) | Lehman, Rose (Baker Hughes Company)
Abstract Amid concerns over negative the environmental impacts of offshore chemicals, Baker Hughes explored new chemistries to develop environmentally friendly kinetic hydrate inhibitors (KHI). Our efforts were focused on improving biodegradability and toxicity of KHIs to meet environmental protection requirements, as well as mitigating challenges in field applications. A novel KHI design with branched polymers containing sugar alcohol ester groups as linkages, was proposed and synthesized. The new KHI polymer demonstrated > 20% biodegradability and >100 mg/L toxicity to seawater algae, and it also exhibited competitive or even better KHI performance to traditional non-biodegradable KHI products. Additionally, new KHI showed improved stability in water/brine at elevated temperatures as compared to traditional KHI products, which might mitigate concerns on polymer deposition at high temperatures.
- Europe (0.34)
- North America > United States (0.29)
- Asia > Middle East (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (0.96)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract Corrosion in pipes is a major challenge for the oil and gas industry as the metal loss of the pipe, as well as solid buildup in the pipe, may lead to an impediment of flow assurance or may lead to hindering well performance. Therefore, managing well integrity by stringent monitoring and predicting corrosion of the well is quintessential for maximizing the productive life of the wells and minimizing the risk of well control issues, which subsequently minimizing cost related to corrosion log allocation and workovers. We present a novel supervised learning method for a corrosion monitoring and prediction system in real time. The system analyzes in real time various parameters of major causes of corrosion such as salt water, hydrogen sulfide, CO2, well age, fluid rate, metal losses, and other parameters. The data are preprocessed with a filter to remove outliers and inconsistencies in the data. The filter cross-correlates the various parameters to determine the input weights for the deep learning classification techniques. The wells are classified in terms of their need for a workover, then by the framework based on the data, utilizing a two-dimensional segmentation approach for the severity as well as risk for each well. The framework was trialed on a probabilistically determined large dataset of a group of wells with an assumed metal loss. The framework was first trained on the training dataset, and then subsequently evaluated on a different test well set. The training results were robust with a strong ability to estimate metal losses and corrosion classification. Segmentation on the test wells outlined strong segmentation capabilities, while facing challenges in the segmentation when the quantified risk for a well is medium. The novel framework presents a data-driven approach to the fast and efficient characterization of wells as potential candidates for corrosion logs and workover. The framework can be easily expanded with new well data for improving classification.
- North America > United States (0.69)
- Asia > Middle East (0.69)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract Natural gas is sampled or produced throughout the lifespan of a field, including geochemical surface survey, mud gas logging, formation and well testing, and production. Detecting and measuring gas is a common practice in many upstream operations, providing gas composition and isotope data for multiple purposes, such as gas show, petroleum system analysis, fluid characterization, and production monitoring. Onsite gas analysis is usually conducted within a mud gas unit, which is operationally unavailable after drilling. Gas samples need be taken from the field and shipped back to laboratory for gas chromatography and isotope-ratio mass spectrometry analyses. Results take a considerable time and lack the resolution needed to fully characterize the heterogeneity and dynamics of fluids within the reservoir. We are developing and testing advanced sensing technology to move gas composition and isotope analyses to field for near real-time and onsite fluid characterization and monitoring. We have developed a novel QEPAS (quartz-enhanced photoacoustic spectroscopy) sensor system, employing a single interband cascade laser, to measure concentrations of methane (C1), ethane (C2), and propane (C3) in gas phase. The quartz fork detection module, laser driver, and interface are integrated as a small sensing box. The sensor, sample preparation enclosures and a computer are mounted in a rack as a gas analyzer prototype for the bench testing for oil industry application. Software is designed for monitoring sample preparation, collecting data, calibration and continuous reporting sample pressure and concentration data. The sensor achieved an ultimate detection limit of 90 ppb (parts per billion), 7 ppb and 3 ppm (parts per million) for C1, C2, and C3, respectively, for one second integration time. The detection limit for C2 made a record for QEPAS technique, and measuring C3 added a new capability to the technique. However, the linearity of the QEPAS sensing were previously reported in the range of 0 to 1000 ppm, which is mainly for trace gas detection. In the study, the prototype was separately tested on standard C1, C2, and C3 with different concentrations diluted in dry nitrogen (N2). Good linearity was obtained for all single components and the ranges of linearity were expanded to their typical concentrations (per cent, %) in natural gas samples from oil and gas fields. The testing on the C1-C2 mixtures confirms that accurate C1 and C2 concentrations in % level can be achieved by the prototype. The testing results on C1-C2-C3 mixtures demonstrate the capability of simultaneous detection of three hydrocarbon components and the probability to determine their precise concentrations by QEPAS sensing. This advancement of simultaneous measuring C1, C2 and C3 concentrations, with previously demonstrated capability for hydrogen sulfide (H2S) and carbon dioxide (CO2) and potential to analyze carbon isotopes (C/C), promotes QEPAS as a prominent optical technology for gas detection and chemical analysis. The capability of measuring multiple gas components and the advantages in small sensor size, high sensitivity, quick analysis, and continuous sensing (monitoring) open the way to use QEPAS technique for in-situ and real-time gas sensing in oil industry. The iterations of QEPAS sensor might be applied in geochemical survey, on-site fluid characterization, time-lapse monitoring of production, and gas linkage detection in the oil industry.
- Asia > Middle East (0.47)
- North America > United States (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.47)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
Abstract Organic and inorganic deposits play a major issue and concern in the wellbore of oil wells. This paper discusses the utilization of a new and novel approach utilizing a thermochemical recipe that shows a successful impact on both organic and inorganic deposits, as an elimination agent, and functions as stimulation fluid to improve the permeability of the near wellbore formation. The new recipe consists of mixing nitrite salt with sulfamic acid in the wellbore at the target zone. The product of this reaction includes heat, acidic salt, and nitrogen gas. The heat of the reaction is enough to liquefy the organic deposits, and the acidic salt will tackle the carbonate scale in the tube and will increase the permeability of the near wellbore area. The nitrogen gas is an inert gas; it will not affect the reaction and will help to flow back the well after the treatment. The experimental work shows an increment in the temperature by 65 °C when mixing the two chemicals. The test was conducted at room conditions and the temperature reached around 90 °C. Adding another 65 °C to the wellbore temperature is enough to melt asphaltene and wax, the acidic salt tackles carbonate scale. As a result, the mixture works on eliminating both the organic and inorganic deposits. The permeability of the limestone sample shows an increment of 65% when treated by the mixture of the reaction recipe. The uniqueness of the new thermochemical recipe is the potential of performing three objectives at the same time; the heat of the reaction removes the organic deposits in the wellbore, the acidic salt tackles carbonate scale, and improves the permeability of the near wellbore zone.
- Asia (1.00)
- North America > United States > Texas (0.47)
- Geology > Mineral (0.70)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract This paper presents an unparalleled engineering assessment conducted to evaluate the feasibility of pre-investing in O2 enrichment technology, with the purpose of increasing the processing capacities of conventional air-based sulfur recovery units (SRUs). Ultimately, the goal is to minimize the overall number of required SRUs for a greenfield gas plant and, consequently, capture a significant cost-avoidance opportunity. The technology review revealed that a high-level O2 enrichment can double the processing capacity of air-based SRU, depending on the H2S content in acid gas. As H2S mole fraction in feed increases, the debottlenecking capability increases. For the project under assessment, the processing capacity of air-based SRUs showed a maximum increase of 80%. On the contrary, operating with high O2 levels, will elevate SRU reaction furnace temperature, and mandates installing high-intensity burners, along with special control and ESD functions, to manage potential risk and ensure safe operation. Additionally, the liquid handling section of SRUs (condensers, collection vessels, degassing vessels, sulfur storage tanks) should be enlarged to accommodate more sulfur production. Typically, the enriched oxygen can be supplied from air separation units (ASUs), which entails significant capital cost. Apart from these special design considerations, there are several advantages for adopting this technology. Oxygen enrichment removes significant nitrogen volumes, which reduces loads on Claus, tail gas treatment, and thermal oxidizer units. Hence, lower capital cost for new plants is acquired due to equipment size reduction. In addition, higher HP steam production and less fuel gas consumption are achieved. Conventionally, O2 enrichment technology is employed in the initial design stage or used to retrofit operating SRUs facilities. However, it is unique to consider O2 enrichment-design requirements as part of new air-based SRUs design for phased program development. The objective is to enable smooth transition to fully O2 enrichment operated SRUs at a later phase of the project without the need for any design modification. This exceptional pre-investment strategy has resulted into reducing the required number of SRUs at phase II from eight to five units; and accordingly, a significant cost avoidance was captured.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Gas processing (1.00)
Abstract Al-Khafji Joint Operations (KJO), a joint operation representing both Saudi and Kuwaiti energy interests in the divided zone, recently encountered obstructions in their offshore field. Routine pressure and temperature surveys revealed that an increasing number of wells were developing scale. The operation required an efficient mechanical tool to clean out extensive accumulated scale bridging within a vertical production string and restore full wellbore accessibility. The well had been previously shut down from operations for five years. The operator considered using a coiled tubing (CT) unit or workover rig to clear the scale but sought a more cost-effective solution. The operator chose a slickline wellbore cleanup and debris breaking tool, which is an impact-driven tool designed to break up scale deposits in a cost-effective, efficient manner. It is jarred down mechanically in the well, each jar applying a short-duration torque via the unique, helically split torque sub. The well's accessible tubing inner diameter was reduced from 2.9-in, nominal to 2-in, at the wireline reentry guide depth. To combat this issue, the slickline technology was deployed with subs increasing in outer diameter (OD) from 1.9-in. to 2.5-in. OD tools. The special features of the wellbore cleanup and debris breaking tool made it better adapted to the well environment and greatly increased the descaling efficiency. Thirty runs enabled the team to clear the scale accumulations down to 3,652 ft (1113 m). The operator confirmed integrity of the tubing at the end of the slickline operation, allowing the slickline team to access the wellbore and run a memory pressure temperature survey to check the well deliverability. The implementation of the wellbore cleanup and debris breaking tool enabled the operator to reduce inventory and overall descaling time. Microscopic and Fourier transform infrared analyses of the scale determined it was calcite (CaCO3) with some small hydrocarbon impurities from either oil or diesel. The descaling rate and cost savings achieved using the wellbore cleanup and debris breaking tool has since resulted in the operator adopting this technology and looking into the feasibility of starting a campaign for scale removal in more than 20 wells. The presence of calcite as a scaling agent is potentially due to the carbonate-saturated formation water and the loss of carbon dioxide from this water to the hydrocarbon phase as pressure decreases. Creating a detailed reservoir characterization that defines fracture orientation, relative aperture produced fluid analysis, and rock properties can help minimize the effect of scale at an early stage. Continuous well monitoring can lead to early identification of scale and determine the need for chemical treatment or further mechanical interventions. This case study demonstrates the benefits of using this wellbore cleanup and debris breaking tool as the first method of mechanical descaling.
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (5 more...)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract In a highly sensitivity oil and gas upstream conditions, there is a need for a real-time interaction platform to cope with harsh environment. The oil and gas business faces data validity constraints in terms of reliability, accuracy, and repeatability to name a few. The Internet of Sensors (IoS), with appropriate utilization, will play a major role in the industry's digital transformation. Predetermined IoS platforms with applicable characteristics are functioning in critical oil and gas environment applications. For example, some oil and gas wells produces harmful gases, like hydrogen sulfide (H2S). Fiber-optic sensors can be used as a leak detection tool for H2S resistance to inform oil and gas curfew if harmful gas is detected at the well site using cloud computing. Scale and corrosion monitoring of external pipelines is one of the integrity challenges. Ultrasonic sensors are embedding for real-time scale thickness feedback and corrosion monitoring by utilizing wireless transmission directly to end-user devices. A paradigm shift is happening with the IoS applications in oil and gas operations for sensitivity, reliability, and accuracy that will add intelligence, smart decisions, and control to the operational landscape. A comprehensive review of the art in oil and gas IoS presented in this paper. The target is to evaluate state-of-the-art IoS platforms for hazardous environments such as oil and gas facilities in terms of type of sensors used, applicability, functionalities, linearity, and accuracy, type of output signals, outputs range, and materials used. This work establishes classification and comparison of the IoS for better data collection, communication, connectivity, observation, and reporting in the world of oil and gas sensors. The IoS platforms classified and compared in tables consisting of different characteristics for the best-suited IoS platform designs in oil and gas appliance applications. This will provide references for IoS design engineers.
- Asia > Middle East > Saudi Arabia (1.00)
- Asia > Middle East > Yemen (0.95)
- Africa > Sudan (0.95)
- (3 more...)
Abstract Minimizing unwanted water production from oil wells is highly required in the petroleum industry. This would lead to improved economic life of mature wells that involve new and innovative technologies. Nanosilica-based sealing fluid has been developed to address problems associated with unwanted water production. The objective of this work is to evaluate a newly developed novel water shutoff system based on nanosilica over a wide range of parameters. This modified nanosilica has a smooth, spherical shape, and are present in a narrow particle size distribution. Therefore, it can be used for water management in different water production mechanisms including high permeability streak, wormhole, and fractured reservoirs. A systematic evaluation of novel nanosilica/activator for water shutoff purposes requires the examination of the chemical properties before, during, and after gelation at given reservoir conditions. These properties are solution initial viscosity, gelation time, injectivity, and strength of the formed gel against applied external forces in different flooding systems. This paper details a promising method to control undesired water production using eco-friendly, cost-effective nanosilica. Experimental results revealed that nanosilica initially exhibited a low viscosity and hence providing a significant advantage in terms of mixing and pumping requirements. Nanosilica gelation time, which is a critical factor in placement of injected-chemical treatment, can be tailored by adjusting the activator concentration to match field requirements at the desired temperature. In addition, core flood tests were conducted in carbonate core plugs, Berea sandstone rock, and artificially fractured (metal tube) to investigate the performance of the chemical treatment. Flow tests clearly indicated that the water production significantly dropped in all tested types of rocks. The environmental scanning electron microscope (SEM) results showed the presence of SiO-rich compounds suggesting that the tested nanosilica product filled the porous media; therefore, it blocked the whole core plug. A novel cost-effective sealant that uses nanotechnology to block the near wellbore region has been developed. The performance and methods controlling its propagation rate into a porous medium will be presented. Based on the outcomes, it must be emphasized that these trivial particles have a promising application in the oil reservoir for water shutoff purposes.
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- North America > United States > Ohio (0.24)
- North America > United States > Kentucky (0.24)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (5 more...)
Optimizing Seawater Based Fracture Fluids Rheology Utilizing Chelating Agents
Othman, Amro (King Fahd University of Petroleum & Minerals) | Aljawad, Murtada Saleh (King Fahd University of Petroleum & Minerals) | Kamal, Muhammad Shahzad (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Patil, Shirish (King Fahd University of Petroleum & Minerals)
Abstract Due to the scarcity and high cost of freshwater, especially in the Gulf region, utilization of seawater as a fracturing fluid gained noticeable interest. However, seawater contains high total dissolved solids (TDS) that may damage the formation and degrade the performance of the fracturing fluids. Numerous additives are required to reduce the damaging effect and improve the viscosity resulting in an expensive and non-eco-friendly fracturing fluid system. Chelating agents, which are environmentally benign, are proposed in this study as the replacement of many additives for seawater fracturing fluids. This study focuses on optimizing chelating agents to achieve high viscosity employing the standard industry rheometers. Carboxymethyl Hydroxypropyl Guar Gum (CMHPG) polymer, which is effective in hydraulic fracturing, was used in this research with 0.5 and 1.0 wt% in deionized water (DW) as well as seawater (SW). It was first tested as a standalone additive at different conditions to provide a benchmark then combined with different concentrations, and pH level chelating agents. In this study the hydration test was conducted through different conditions. It was observed that CMHPG, when tested as a standalone additive, provided slightly higher viscosity in SW compared to DW. Also, increasing polymer concentration from 0.5 to 1.0 wt% provided three folds of viscosity. The viscosity did not show time dependence behavior at room temperature for the aforementioned experiments where all hydration tests were run at 511 1/s shear rate. Temperature, however, had a significant impact on both viscosity magnitude and behavior. At 70 °C, the fluid viscosity increased with time where low viscosity was achieved early on but kept increasing with shearing time. Similarly, high pH chelating agents provided time dependant viscosity behavior when mixed with CMHPG. This behavior is important as low viscosity is favorable during pumping but high viscosity when the fluids hit the formation. The study investigates the possibility of utilizing chelating agents with seawater to replace numerous additives. It acts as a crosslinker at early shearing times, where a gradual increase in viscosity was observed and a breaker in the reservoir harsh conditions. It also captures the divalent ions that are common in seawater, which replaces the need for scale inhibitors. The viscosity increase behavior can be controlled by adjusting the pH level, which could be desirable during operations.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract Viscoelastic surfactant (VES)-based acids have been employed for acidizing jobs due to their ability to build up sufficient viscosity for acid diversion and fluid loss reduction, and to break into low viscosity after the treatment is completed. This work studied rheological properties of a new zwitterionic viscoelastic surfactant-based stimulation fluid. İmpacts of many variables on the rheological characteristics of the VES-based live and spent acids were examined. Rheological experiments were conducted using a high pressure/high temperature (HPHT) viscometer. Viscosity measurements were performed between the temperatures of 78 to 350°F and shear rates of 10 to 935 s at 300 psi. Examined acid additives included: corrosion inhibitor, formic acid, methanol, demulsifier, H2S scavenger, iron control agents, and mutual solvent. As a contaminant, the effect of Fe (III) was investigated. In addition, the impacts of surfactant concentration, salt type and salt concentration on the viscosity of the VES-based acid systems were tested. Experimental results indicated that the new VES-based acid system exhibits a sufficient viscosity for acid diversion at temperatures up to 270°F. Apparent viscosity of the spent acid showed a strong relation with surfactant concentration, salt type and salt concentration. Corrosion inhibitor concentration above 0.5 vol% caused a notable loss in the viscosity as the temperature increased gradually. Dependency on methanol was strong enough that it resulted in a decline of the apparent viscosity of both live and spent acid solutions. H2S scavenger and iron control agents (citric acid and EDTA) did not alter the viscous behavior notably, while demulsifier and mutual solvent caused a reduction in the apparent viscosity. Fe (III) contamination caused fluctuations in the live acid viscosity due to generated VES-iron complex. In spent condition, this complex caused phase separation that resulted in loss of viscosity. On the basis of the results obtained, optimum conditions to achieve the desired rheological profile for a successful well stimulation operation are presented.
- North America > United States > Texas (0.68)
- Europe (0.68)
- Asia (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Acidizing (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)