scholarly journals Low Technological Biological Treatment of Source Separated Waste in a Biocell

2017 ◽  
Author(s):  
Janne H. Jarstad ◽  
L.Semb Vestgarden ◽  
B. E. Berg
Keyword(s):  
Pilot Project ◽  
Gas Production ◽  
Test Period ◽  
Gas Wells ◽  
Gas Leakage ◽  
Methane Potential ◽  
On Line ◽  
Waste Degradation ◽  
Anaerobic Testing ◽  
Considerable Period

In 2009 the Norwegian government banned biodegradable waste in landfills to mitigate climate gas production. To be able to stabilize source separated waste before landfilling a constructed biocell has been tested during a four year period. The research is part of a pilot project organized by Avfall Norge. A total amount of 12 000 tons of waste from both industry and households were embedded in the biocell. Before loading, the waste fractions were characterized both in macro and micro scale. Anaerobic testing in lab scale documented the methane potential in different waste fractions. Especially car fluff contained toxic components which suppressed biodegradation. To avoid greenhouse gas leakage the biocell was constructed as a closed system with synthetic capping and gas wells coupled to a compressor. While the biogas was flared the leachate was collected and recycled. Leachate contains both nutrients and DOC which is supposed to increase the biological activity. During the first part of the test period the BOD/COD was above 0.5 before it declined. In addition both inorganic and organic environmental harmful components were analyzed in the leachate. Levels of heavy metal decreased during treatment. The methane production was detected on-line with IR. Both the production and gas phase concentration varied during the test period. A total of five gas wells were positioned at different levels in the biocell. Only one of them produced biogas for a considerable period. This presentation will focus on biocell construction and waste degradation related to variation in leachate constituents as a function of time.

Chemical Deliquification of Unconventional Gas Wells

2014 ◽  
Author(s):  
K.. Francis-LaCroix ◽  
D.. Seetaram
Keyword(s):  
Natural Gas ◽  
Best Practice ◽  
Oil And Gas ◽  
Large Deviation ◽  
Cost Effective ◽  
Gas Production ◽  
Lessons Learned ◽  
Offshore Platforms ◽  
Gas Wells ◽  
Current Production

Abstract Trinidad and Tobago offshore platforms have been producing oil and natural gas for over a century. Current production of over 1500 Bcf of natural gas per year (Administration, 2013) is due to extensive reserves in oil and gas. More than eighteen of these wells are high-producing wells, producing in excess of 150 MMcf per day. Due to their large production rates, these wells utilize unconventionally large tubulars 5- and 7-in. Furthermore, as is inherent with producing gas, there are many challenges with the production. One major challenge occurs when wells become liquid loaded. As gas wells age, they produce more liquids, namely brine and condensate. Depending on flow conditions, the produced liquids can accumulate and induce a hydrostatic head pressure that is too high to be overcome by the flowing gas rates. Applying surfactants that generate foam can facilitate the unloading of these wells and restore gas production. Although the foaming process is very cost effective, its application to high-producing gas wells in Trinidad has always been problematic for the following reasons: Some of these producers are horizontal wells, or wells with large deviation angles.They were completed without pre-installed capillary strings.They are completed with large tubing diameters (5.75 in., 7 in.). Recognizing that the above three factors posed challenges to successful foam applications, major emphasis and research was directed toward this endeavor to realize the buried revenue, i.e., the recovery of the well's potential to produce natural gas. This research can also lead to the application of learnings from the first success to develop treatment for additional wells, which translates to a revenue boost to the client and the Trinidad economy. Successful treatments can also be used as correlations to establish an industry best practice for the treatment of similarly completed wells. This paper will highlight the successes realized from the treatment of three wells. It will also highlight the anomalies encountered during the treatment process, as well as the lessons learned from this treatment.

Lithology and sedimentary heterogeneity of the Longmaxi Shale in the southern Sichuan Basin, China

2021 ◽  
pp. 1-49
Author(s):  
Boling Pu ◽  
Dazhong Dong ◽  
Ning Xin-jun ◽  
Shufang Wang ◽  
Yuman Wang ◽  
...  
Keyword(s):  
Continental Shelf ◽  
Deep Water ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Sedimentary Environment ◽  
Gas Production ◽  
Carbonaceous Shale ◽  
Gas Wells ◽  
Longmaxi Shale ◽  
Siliceous Shale

Producers have always been eager to know the reasons for the difference in the production of different shale gas wells. The Southern Sichuan Basin in China is one of the main production zones of Longmaxi shale gas, while the shale gas production is quite different in different shale gas wells. The Longmaxi formation was deposited in a deep water shelf that had poor circulation with the open ocean, and is composed of a variety of facies that are dominated by fine-grained (clay- to silt-size) particles with a varied organic matter distribution, causing heterogeneity of the shale gas concentration. According to the different mother debris and sedimentary environment, we recognized three general sedimentary subfacies and seven lithofacies on the basis of mineralogy, sedimentary texture and structures, biota and the logging response: (1) there are graptolite-rich shale facies, siliceous shale facies, calcareous shale facies, and a small amount of argillaceous limestone facies in the deep - water shelf in the Weiyuan area and graptolite-rich shale facies and carbonaceous shale facies in the Changning area; (2) there are argillaceous shale facies and argillaceous limestone facies in the semi - deep - water continental shelf of the Weiyuan area and silty shale facies in the Changning area; (3) argillaceous shale facies are mainly developed in the shallow muddy continental shelf in the Weiyuan area, while silty shale facies mainly developed in the shallow shelf in the Changning area. Judging from the biostratigraphy of graptolite, the sedimentary environment was different in different stages.

scholarly journals Viscoelastic behavior of a casing material and its utilization in premium connections in high-temperature gas wells

2018 ◽  
Vol 10 (12) ◽  
pp. 168781401881745 ◽  
Author(s):  
Ying Zhang ◽  
Zhanghua Lian ◽  
Mi Zhou ◽  
Tiejun Lin
Keyword(s):  
High Temperature ◽  
Contact Pressure ◽  
Viscoelastic Model ◽  
Viscoelastic Behavior ◽  
Element Model ◽  
Gas Production ◽  
Prony Series ◽  
Gas Well ◽  
Gas Leakage ◽  
High Temperature Gas

At the high or extra-high temperatures in a natural gas oilfield, where the premium connection is employed by casing, gas leakage in the wellbore is always detected after several years of gas production. As the viscoelastic material’s mechanical properties change with time and temperature, the relaxation of the contact pressure on the connection sealing surface is the main reason for the gas leakage in the high-temperature gas well. In this article, tension-creep experiments were conducted. Furthermore, a constitutive model of the casing material was established by the Prony series method. Moreover, the Prony series’ shift factor was calculated to study the thermo-rheological behavior of the casing material ranging from 120°C to 300°C. A linear viscoelastic model was implemented in ABAQUS, and the simulation results are compared to our experimental data to validate the methodology. Finally, the viscoelastic finite element model is applied to predict the relaxation of contact pressure on the premium connections’ sealing surface versus time under different temperatures. And, the ratio of the design contact pressure and the intending gas sealing pressure is recommended for avoiding the premium connections failure in the high-temperature gas well.

A Volumetric Analysis of Almond Formation (Cretaceous, Mesaverde Group) Gas Production in the Coal Gulch-Echo Springs Standard Draw Field Complex, Washakie Basin, Southwest Wyoming

1998 ◽  
Vol 1 (04) ◽  
pp. 328-337
Author(s):  
D.N. Burch ◽  
R.M. Cluff
Keyword(s):  
Gas Flow ◽  
Rocky Mountain ◽  
Volumetric Analysis ◽  
Gas Production ◽  
Total Production ◽  
Total Contribution ◽  
Gas Leakage ◽  
Original Manuscript ◽  
Field Area ◽  
Mesaverde Group

This paper (SPE 50995) was revised for publication from paper SPE 38368, first presented at the 1997 SPE Rocky Mountain Regional Meeting, Casper, Wyoming, 18-21 May. Original manuscript received for review 18 June 1997. Revised manuscript received 27 April 1998. Paper peer approved 1 June 1998. Summary The Coal Gulch-Echo Springs-Standard Draw field complex is one of the largest commercial gas accumulations in the Rocky Mountain region with over 1 Tcf of gas of recoverable reserves. Gas is produced from both the Upper Almond barrier bar and shoreline sandstones at the top of the Mesaverde Group (Upper Cretaceous) and from underlying Main Almond fluvial and marginal marine sandstones. Some recently published models suggest that although the bulk of the produced gas in the fields is from the Upper Almond bar interval, simple volumetric calculations can only account for about 50% of the estimated ultimate recovery from this reservoir. These models imply that the depleting Upper Almond reservoir might be actively recharged by gas leakage from deeper Main Almond sandstones, with contributions from the deeper reservoirs of up to 10 to 30 Bcf of gas per well. This is in stark contrast to typical Main Almond-only producers outside the field area, which have mean reserves of less than 1 Bcf of gas and rarely produce more than 2 Bcf of gas per well. The implication is that the Upper Almond bar sand acts as a gas flow conduit, and its presence is required for efficient drainage of the Main Almond. We determined the gas in place (GIP) for all field wells drilled before 1993. The GIP within the Upper Almond reservoir only was determined by detailed openhole log analysis and volumetric mapping to be 1,050 Bcf of gas. Total reserves from all producing intervals (Upper Almond and Main Almond combined) are estimated by decline curve analysis to be 1,003 Bcf of gas. The Main Almond lenticular reservoirs contribution to total production is then assumed to be statistically similar to Main Almond-only producers outside the field area, giving an estimated total contribution from Main Almond completions of 96 Bcf of gas; therefore, the recovery factor from the Upper Almond alone is estimated to be (1003 - 96)/1050=86%. We conclude that field volumetrics do not support a disproportionate contribute of Main Almond gas to the total field production, nor does the volumetric analysis support the active reservoir recharge hypothesis. P. 328

First Successful Autonomous ICD Pilot for GOR Management Across ADNOC Offshore

2021 ◽  
Author(s):  
Fazeel Ahmad ◽  
Zohaib Channa ◽  
Fahad Al Hosni ◽  
Salman Farhan Nofal ◽  
Ziad Talat Libdi ◽  
...  
Keyword(s):  
Oil Production ◽  
Pilot Project ◽  
Gas Production ◽  
Simulation Software ◽  
Production Performance ◽  
Production Operation ◽  
Open Hole ◽  
Early Production ◽  
Horizontal Wellbore ◽  
Selection Factors

Abstract The paper discusses the pilot project in ADNOC Offshore to assess the Autonomous Inflow Control Device (AICD) technology as an effective solution for increasing oil production over the life of the field. High rate of water and gas production in horizontal wells is one of the key problems from the commencement of operation due to the high cost of produced water and gas treatment including several other factors. Early Gas breakthrough in wells can result in shut-in to conserve reservoir energy and to meet the set GOR guidelines. The pilot well was shut-in due to high GOR resulted from the gas breakthrough. A pilot project was implemented to evaluate the ability of autonomous inflow control technology to manage gas break through early in the life of the well spanned across horizontal wellbore. And also to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. Each compartment in the pilot well was equipped with AICD Screens and Swell-able Packers across horizontal open hole wellbore to evaluate oil production and defer gas breakthrough. Some AICDs were equipped with treatment valve for the compartments that needed acid simulation to enhance the effectiveness of the zone. The selection factors for installing number of production valves in the pilot well per each AICD was based on reservoir and field data. Pre-modeling of the horizontal wellbore section with AICD was performed using commercial simulation software (NETool). After the first pilot was completed, a detailed technical analysis was conducted and based on the early production results from the pilot well showed that AICD completions effectively managed gas production by delaying the gas break through and restricting gas inflow from the reservoir with significant GOR reduction ±40% compared to baseline production performance data from the open hole without AICD thus increasing oil production. The pilot well performed positively to the AICD completion allowing to produce healthy oil and meeting the guidelines. The early production results are in line with NETool simulation modelling, thereby increasing assurance in the methods employed in designing the AICD completion for the well and candidate selection. This paper discusses the successful AICD completion installation and production operation in pilot well in ADNOC Offshore to manage GOR and produced the well with healthy oil under the set guidelines. This will enable to re-activate wells shut-in due to GOR constraint to help meeting the sustainable field production target.

Technology Focus: Unconventional and Tight Reservoirs (July 2021)

2021 ◽  
Vol 73 (07) ◽  
pp. 57-57
Author(s):  
Leonard Kalfayan
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Alternative Methods ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Liquid Loading ◽  
Well Production ◽  
Tight Carbonate ◽  
Water Blocking ◽  
Tight Reservoirs

As unconventional oil and gas fields mature, operators and service providers are looking toward, and collaborating on, creative and alternative methods for enhancing production from existing wells, especially in the absence of, or at least the reduction of, new well activity. While oil and gas price environments remain uncertain, recent price-improvement trends are supporting greater field testing and implementation of innovative applications, albeit with caution and with cost savings in mind. Not only is cost-effectiveness a requirement, but cost-reducing applications and solutions can be, too. Of particular interest are applications addressing challenging well-production needs such as reducing or eliminating liquid loading in gas wells; restimulating existing, underperforming wells, including as an alternative to new well drilling and completion; and remediating water blocking and condensate buildup, both of which can impair production from gas wells severely. The three papers featured this month represent a variety of applications relevant to these particular well-production needs. The first paper presents a technology and method for liquid removal to improve gas production and reserves recovery in unconventional, liquid-rich reservoirs using subsurface wet-gas compression. Liquid loading, a recurring issue downhole, can severely reduce gas production and be costly to remediate repeatedly, which can be required. This paper discusses the full technology application process and the supportive results of the first field trial conducted in an unconventional shale gas well. The second paper discusses the application of the fishbone stimulation system and technique in a tight carbonate oil-bearing formation. Fishbone stimulation has been around for several years now, but its best applications and potential have not necessarily been fully understood in the well-stimulation community. This paper summarizes a successful pilot application resulting in a multifold increase in oil-production rate and walks the reader through the details of the pilot candidate selection, completion design, operational challenges, and lessons learned. The third paper introduces and proposes a chemical treatment to alleviate phase trapping in tight carbonate gas reservoirs. Phase trapping can be in the form of water blocking or increasing condensate buildup from near the wellbore and extending deeper into the formation over time. Both can reduce relative permeability to gas severely. Water blocks can be a one-time occurrence from drilling, completion, workover, or stimulation operations and can often be treated effectively with solvent plus proper additive solutions. Similar treatments for condensate banking in gas wells, however, can provide only temporary alleviation, if they are even effective. This paper proposes a technique for longer-term remediation of phase trapping in tight carbonate gas reservoirs using a unique, slowly reactive fluid system. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200345 - Insights Into Field Application of Enhanced-Oil-Recovery Techniques From Modeling of Tight Reservoirs With Complex High-Density Fracture Network by Geng Niu, CGG, et al. SPE 201413 - Diagnostic Fracture Injection Test Analysis and Simulation: A Utica Shale Field Study by Jeffery Hildebrand, The University of Texas at Austin, et al.

AI for Production Forecasting and Optimization of Gas Wells: A Case Study on a Middle-East Gas Field

2021 ◽  
Author(s):  
Jimmy Thatcher ◽  
Abdul Rehman ◽  
Ivan Gee ◽  
Morgan Eldred
Keyword(s):  
Machine Learning ◽  
Optimal Parameter ◽  
Gas Production ◽  
Production Optimization ◽  
Machine Learning Techniques ◽  
Gas Wells ◽  
Optimal Production ◽  
Unsupervised Machine Learning ◽  
Production Forecasting ◽  
Run Time

Abstract Oil & Gas extraction companies are using a vast amount of capital and expertise on production optimization. The scale and diversity of information required for analysis is massive and often leading to a prioritization between time and precision for the teams involved in the process. This paper provides a success story of how artificial intelligence (AI) is used to dynamically and effeciently optimize and predict production of gas wells. In particular, we focus on the application of unsupervised machine learning to identify under different potential constraints the optimal production parameter settings that can lead to maximum production. A machine learning model is supported by a decision support system that can enhance future drilling operations and also help answer important questions such as why a particular well or group of wells is producing differently than others of the same type or what kind of parameters that work on different wells in different conditions. The model can be advanced to optimize within field constraints such as facility handling capacity, quotas, budget or emmisions. The methods used were a combination of similarity measures and unsupervised machine learning techniques which were effective in identifying wells and clusters of wells that have similar production and behavioral profiles. The clusters of wells were then used to identify the process path (specific drilling and completion, choke size, chemicals, etc processes) most likely to result in optimal production and to identify the most impactful variables on production rate or cumulative production via an additional clustering of the principle charactersitics of the well. The data sets used to build these models include but are not limited to gas production data (daily volume), drilling data (well logs, fluid summary etc.), completion data (frac, cement bond logs), and pre-production testing data (choke, pressure etc.) Initial results indicate that this approach is a feasible approach, on target in terms of accuracy with traditional methods and represents a novel, data driven, method of identifying optimal parameter settings for desired production levels; with the ability to perform forecasts and optimization scenarios in run-time. The approach of using machine learning for production forecasting and production optimization in run-time has immense values in terms of the ability to augment domain expertise and create detailed studies in a fraction of the time that is typically required using traditional approaches. Building on same approach to optimise the field to deliver most reliable or most effeciently against a parameter will be an invaluable feature for overall asset optimisation.

TOURIST DESTINATION QUALITY MANAGEMENT SYSTEM (CASE STUDY - PULA)

2004 ◽  
Vol 10 (3-4) ◽  
pp. 1-30
Author(s):  
Vinka Cetinski ◽  
Violeta Šugar
Keyword(s):  
Quality Management ◽  
Management System ◽  
Quality Management System ◽  
Pilot Project ◽  
City Region ◽  
Tourist Destination ◽  
Starting Point ◽  
Private And Public ◽  
On Line ◽  
Public And Private Sector

The contemporary tourist product includes attractions, created by nature as well as humans. Attractions represent a part o f some specific destination, place, city, region, even continent. Destination is to be viewed as a whole, which requires the quality management of both its development and the foundation of attraction resource. Quality management of a tourist destination is based on a synergy, meaning cooperation of all stakeholders in public and private sector. Without attractions there is no tourism, no tourist destination. Without quality management, precisely quality development management, a tourist destination would be left to a random, chaotic construction, the maximum usage o f resources, in short, to the threat o f loosing any attractiveness in the future. The quality management system of Pula as a tourist destination, suggested in this paper, should be established on the quality databases, available to the users connected through a network, all the stakeholders in both private and public sector. On-line users would constitute a Destination Management Network (DMN), i.e. a competitive diamond of Pula, a pilot-project whose success could become a parameter, a standard for other similar destinations. On-line information, from those statistical to the ones attached to tourist supply, products and attractions o f the destination, would refer to the Pula know-how. Knowledge, information and human capital are the starting point of the quality management and the competitive diamond framework of the Pula Destination Management Network.

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